Wellbore fluids comprising mineral particles and methods relating thereto

ABSTRACT

Mineral particles may provide for wellbore fluids with tailorable properties and capabilities. Such wellbore fluids may be included as a portion of a wellbore drilling assembly that includes a pump in fluid communication with a wellbore via a feed pipe; and a wellbore fluid disposed in at least one selected from the group consisting of the pump, the feed pipe, the wellbore, and any combination thereof, wherein the wellbore fluid comprises a base fluid and a plurality of mineral particles, for example, mineral particles that comprise at least one selected from the group consisting of manganese carbonate, NixFe (x=2-3), copper oxide, and any combination thereof, the mineral particles having a median diameter between about 5 nm and about 5000 microns.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a continuation-in-part of and claims priorityto U.S. patent application Ser. No. 13/752,788 filed on Jan. 29, 2013,entitled “Wellbore Fluids Comprising Mineral Particles and MethodsRelating Thereto,” the entire disclosure of which is incorporated hereinby reference.

BACKGROUND

The present invention relates to mineral particles that provide forwellbore fluids with tailorable properties and capabilities, and methodsrelating thereto.

In the exploration and recovery of hydrocarbons from subterraneanformations, a variety of wellbore operations are performed, e.g.,drilling operations, cementing operations, and stimulation operations.One physical property of the wellbore fluids used in conjunction withthese wellbore operations is density. For example during drillingoperations, the density of a wellbore fluid must be carefully controlledso as to exert sufficient pressure to stabilize the walls of thewellbore, e.g., to prevent blowouts, while simultaneously not exertingexcess pressure that can cause damage to the surrounding subterraneanformation. In another example, the density of spacer fluids andcementing operations must be carefully balanced so as to minimize orprevent mixing of other wellbore fluids on either side of the spacerfluid (e.g., a drilling fluid and a cementing fluid).

Changing the density of wellbore fluids is often achieved with the useof particles (often referred to as weighting agents). One of the mostcommon weighting agent used in the exploration recovery of hydrocarbonshas been barite. However, as the exploration and recovery ofhydrocarbons expands to subterranean formations with harsher conditions(e.g., extreme temperatures, higher pressures, increased depths, and newlithologies) the complexity of wellbore fluids often increases. Wellborefluid complexity can lead to negative synergistic effects betweenwellbore additives, including barite. For example, the combination ofbarite to increase density and viscosifiers to mitigate particlesettling can lead to wellbore fluids with viscosities too high to bepumped efficiently and effectively in a wellbore. Accordingly, there isa need for wellbore additives to serve multiple purposes to minimize thenumber of different additives in a wellbore fluid so as to mitigatenegative synergistic effects with each other.

SUMMARY OF THE INVENTION

The present invention relates to mineral particles that provide forwellbore fluids with tailorable properties and capabilities, and methodsrelating thereto.

One embodiment of the present invention provides for a wellbore drillingassembly that includes a pump in fluid communication with a wellbore viaa feed pipe; and a wellbore fluid disposed in at least one selected fromthe group consisting of the pump, the feed pipe, the wellbore, and anycombination thereof, wherein the wellbore fluid comprises a base fluidand a plurality of mineral particles that comprise at least one selectedfrom the group consisting of manganese carbonate, NixFe (x=2-3), copperoxide, and any combination thereof, the mineral particles having amedian diameter between about 5 nm and about 5000 microns.

Another embodiment of the present invention provides for a wellboredrilling assembly that includes a pump in fluid communication with awellbore via a feed pipe; a drill string with drill bit attached to thedistal end of the drill string; and a wellbore fluid in contact with thedrill bit, wherein the wellbore fluid comprises a base fluid and aplurality of mineral particles, the plurality of mineral particlescomprising at least one selected from the group consisting of manganesecarbonate, NixFe (x=2-3), copper oxide, and any combination thereof, andthe mineral particles having a median diameter between about 5 nm andabout 100 microns.

Yet another embodiment of the present invention provides for a wellboredrilling assembly that includes a pump capable of introducing a fluidinto a wellbore via a feed pipe; a fluid processing unit capable ofreceiving the fluid from a wellbore via an interconnecting flow line;and a wellbore fluid disposed in at least one selected from the groupconsisting of the pump, the feed pipe, the wellbore, the interconnectingflow line, the fluid processing unit, and any combination thereof,wherein the wellbore fluid comprises a base fluid and a plurality ofmineral particles that comprise at least one selected from the groupconsisting of manganese carbonate, NixFe (x=2-3), copper oxide, and anycombination thereof, the mineral particles having a median diameterbetween about 5 nm and about 5000 microns.

The features and advantages of the present invention will be readilyapparent to those skilled in the art upon a reading of the descriptionof the preferred embodiments that follows.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of thepresent invention, and should not be viewed as exclusive embodiments.The subject matter disclosed is capable of considerable modifications,alterations, combinations, and equivalents in form and function, as willoccur to those skilled in the art and having the benefit of thisdisclosure.

FIGS. 1A-B illustrate examples of theoretical multi-modal diameterdistributions for particles.

FIG. 2 illustrates exemplary recovery and recycling processes accordingto at least some embodiments described herein.

FIG. 3 illustrates an exemplary wellbore drilling assembly for use inconjunction with the mineral particles, related fluids, and relatedmethods described herein.

DETAILED DESCRIPTION

The present invention relates to mineral particles that provide forwellbore fluids with tailorable properties and capabilities, and methodsrelating thereto.

The present invention provides for, in some embodiments, mineralparticles that can be used in subterranean applications as uniqueweighting agents. Further, in some embodiments, the mineral particlesdescribed herein may advantageously have multiple properties thatprovide for desirable effects that other wellbore additives wouldtraditionally provide for (e.g., viscosifiers). Accordingly, the mineralparticles described herein may advantageously serve as weighting agentsand other wellbore additives select viscosifiers, cement particles, sagcontrol additives, proppants, and the like), which may allow for theproduction of wellbore fluids with tailorable properties andcapabilities using minimal types of wellbore additives. As such, the useof the mineral particles described herein in wellbore fluids formultiple purposes may reduce the complexity, and consequently the cost,of such wellbore fluids.

Further, in some weighting agents contexts, the mineral particlesdescribed herein may, in some embodiments, have additional advantagesover traditional barite weighting agents. For example, in the currentbarite mining operations, the weighting agents produced can include upto about 21% sand, which can be abrasive to many wellbore tools. Theminerals described herein may advantageously be less abrasive, asdescribed further herein, thereby prolonging the life of wellbore tools(e.g., pumps, drill bits, drill string, and a casing). In anotherexample, the mineral particles described herein may, in someembodiments, be degradable, which allows for unique opportunities forcleanup and cementing operations, as described further herein. In yetanother example, the mineral particles described herein may, in someembodiments, be recovered and recycled for use in other mineralapplications (e.g., smelting). The recycling of the mineral particlesfurther reduces costs and environmental impact of the exploration andrecovery of hydrocarbons.

It should be noted that when “about” is used herein at the beginning ofa numerical list, “about” modifies each number of the numerical list. Itshould be noted that in some numerical listings of ranges, some lowerlimits listed may be greater than some upper limits listed. One skilledin the art will recognize that the selected subset will require theselection of an upper limit in excess of the selected lower limit.

In some embodiments of the present invention, wellbore additives and/orwellbore fluids may comprise the mineral particles described herein.Such wellbore additives and/or wellbore fluids may be used inconjunction with a plurality of wellbore operations. As used herein, theterms “wellbore additive” and “wellbore fluid” refer to any additive orfluid, respectively, suitable for use in conjunction with a wellborepenetrating a subterranean formation and does not imply any particularaction by the additive or fluid. Similarly, the term “wellboreoperation” refers to any treatment or operation suitable for use inconjunction with a wellbore and/or subterranean formation, e.g.,drilling operations, lost circulation operations, fracturing operations,cementing operations, completion operations, and the like.

It should be noted that unless otherwise specified, the term “mineralparticles” encompasses single types of mineral particles andcombinations of more than one type of mineral particle described herein.Distinctions between types of mineral particles may, in someembodiments, be defined by at least one of mineral composition,production method, average diameter, diameter distribution, shape,presence or absence of coating, coating composition, and the like, andany combination thereof.

I. Mineral Particles

In some embodiments, the mineral particles described herein suitablefor, inter alia, increasing the density of wellbore fluids describedherein may have a specific gravity ranging from a lower limit of about2.6, 3, 4, 4.5, 5, or 5.5 to an upper limit of about 20, 15, 10, 9, 8,or 7, and wherein the specific gravity may range from any lower limit toany upper limit and encompasses any subset therebetween.

In some embodiments, the mineral particles described herein may comprisetraditional minerals and/or non-traditional minerals useful forweighting a wellbore fluid, which may depend on, inter alia, theapplication, the desired wellbore fluid properties, the availability ofthe minerals, and the like, and any combination thereof.

Examples of traditional minerals useful for weighting a wellbore fluidinclude, but are not limited to, BaSO₄, CaCO₃, (Ca,Mg)CO₃, FeCO₃, Fe₂O₃,α-Fe₂O₃, α-FeO(OH), Fe₃O₄, FeTiO₃, (Fe,Mg)SiO₄, SrSO₄, MnO, MnO₂, Mn₂O₃,Mn₃O₄, Mn₂O₇, MnO(OH), (Mn²⁺,Mn³⁺)₂O₄, and suitable combinationsthereof. Some embodiments described herein may involve grinding bulkmineral materials so as to yield the mineral particles described herein.Additional examples of traditional minerals in their native form mayinclude, but are not limited to, barite, calcium carbonate, dolomite,hematite, siderite, magnetite, manganese dioxide, manganese (IV) oxide,manganese oxide, manganese tetraoxide, manganese (II) oxide, manganese(III) oxide, and suitable combinations thereof.

Examples of non-traditional minerals useful for weighting a wellborefluid include, but are not limited to, AgI, AgCl, AgBr, AgCuS, AgS,Ag₂S, Ag₃SbS₃, AgSbS₂, AgSbS₂, Ag₅SbS₄, (AgFe₂S₃), Ag₃AsS₃, Ag₃AsS₃,Cu(Ag,Cu)₆Ag₉As₂S₁₁, [(Ag,Cu)₆(Sb,As)₂S₇][Ag₉CuS₄], Ag₃AuTe₂,(Ag,Au)Te₂, Ag₂Te, Al₂O₃, Al₂SiO₅, AsSb, (Co,Ni,Fe)As₃, PtAs₂, AuTe₂,BaCO₃, BaO, BeO, Bi, BiOCl, (BiO)₂CO₃, BiO₃, Bi₂S₃, Bi₂O₃, CaO, CaF₂,CaWO₄, CdS, CdTe, Ce₂O₃, CoAsS, Co⁺²Co⁺³ ₂S₄, (Fe,Mg)Cr₂O₄, Cr₂O₃, Cu,CuO, Cu₂O, CuS, Cu₂S, CuS₂, Cu₉S₅, CuFeS₂, Cu₅FeS₄, CuS.Co₂S₃,Cu₃ASO₄(OH)₃, Cu₃AsS₄, Cu₁₂As₄S₁₃, Cu₂(AsO₄)(OH), CuPb₁₃Sb₇S₂₄,CuSiO₃.H₂O, Fe₃Al₂(SiO₄)₃, Fe²⁺Al₂O₄, Fe₂SiO₄, FeWO₄, FeAs₂, FeAsS, FeS,FeS₂, Fe_((1-x))S (wherein x=0 to 0.2), (Fe,Ni)₉S₈, Fe²⁺Ni₂ ³⁺S₄,(Fe,Mn)WO₄, Fe²⁺Nb₂O₆, (Mn,Fe,Mg)(Al,Fe)₂O₄, CaFe²⁺ ₂Fe³⁺Si₂O₇O(OH),(YFe³⁺Fe²⁺U,Th,Ca)₂(Nb,Ta)₂O₈, HgS, Hg₂Cl₂, MgO, MnCO₃, Mn₂S, Mn₂SiO₄,MnWO₄, Mn(II)₃Al₂(SiO₄)₃,(Na_(0.3)Ca_(0.1)K_(0.1))(Mn⁴⁺,Mn³⁺)₂O₄.1.5H₂O, (Mn,Fe)₂O₃,(Mn²⁺,Fe²⁺,Mg)(Fe³⁺,Mn³⁺)₂O₄, (Mn²⁺,Mn³⁺)₆[O₈|SiO₄],Ca(Mn³⁺,Fe³⁺)₁₄SiO₂₄, Ba(Mn²⁺)(Mn⁴⁺)₈O₁₆(OH)₄, CaMoO₄, MoS₂, MoO₂, MoO₃,NbO₄, (Na,Ca)₂Nb₂O₆(OH,F), (Y,Ca,Ce,U,Th)(Nb,Ta,Ti)₂O₆,(Y,Ca,Ce,U,Th)(Ti,Nb,Ta)₂O₆, (Fe,Mn)(Ta,Nb)₂O₆, (Ce,La)PO₄,(Ce,La,Ca)BSiO₅, (Ce,La)CO₃F, (Y,Ce)CO₃F, (U,Ca,Y,Ce)(Ti,Fe)₂, NiO,NiAs₂, NiAs, NiAsS, Ni_(x)Fe (x=2-3), (Ni,Co)₃S₄, NiS, PbTe, PbSO₄,PbCrO₄, PbWO₄, PbSiO₃, PbCO₃, (PbCl)₂CO₃, Pb₅(PO₄)₃Cl, Pb₅(AsO₄)₃Cl,Pb²⁺ ₂Pb⁴⁺O₄, Pb₅Au(Te,Sb)₄S₅₋₈, Pb₅Sb₈S₁₇, PbS, Pb₉Sb₈S₂₁,Pb₁₄(Sb,As)₆S₂₃, Pb₅Sb₄S₁₁, Pb₄FeSb₆S₁₄, PbCu[(OH)₂|SO₄], PbCuSbS₃,(Cu,Fe)₁₂Sb₄S₁₃, Sb₂S₃, (Sb³⁺,Sb⁵⁺)O₄, Sb₂SnO₅, Sc₂O₃, SnO, SnO₂,Cu₂FeSnS₄, SrO, SrCO₃, (Na,Ca)₂Ta₂O₆(O,OH,F), ThO₂, (Th,U)SiO₄, TiO₂,UO₂, V₂O₃, VO₂, V₂O₅, Pb₅(VO₄)₃Cl, VaO, Y₂O₃, YPO₄, ZnCO₃, ZnO, ZnFe₂O₄,ZnAl₂O₄, ZnCO₃, ZnS, ZnO, (Zn_((1-x))Fe_((x))S), (Zn,Fe)S, ZrSiO₄, ZrO₂,ZrSiO₄, and suitable combinations thereof. Additional examples ofnon-traditional minerals in their native form may include, but are notlimited to, acanthite, alamandite, allemontite, altaite, aluminum oxide,andalusite, anglesite, antimony sulfide, antimony tin oxide, antimonytrioxide, argentite, arsenopyrite, awaruite, barium carbonate, bariumoxide, bastnaesite, beryllium oxide, birnessite, bismite, bismuth,bismuth oxycarbonates, bismuth oxychloride, bismuth sulfide, bismuthsulfide, bismuth trioxide, bismuth (III) oxide, bixbyite, bornite,boulangerite, bournonite, brannerite, braunite, bravoite, bromyrite,cadimum sulfide, cadimum telluride, calayerite, calcium oxide, calomel,carrollite, cassiterite, celestine, cerargyrite, cerium oxide,cerussite, cervantite, chalcocite, chalcopyrite, chromite, chromiumoxide, cinnabar, clinoclase, cobaltite, columbite, copper, copper oxide,copper sulfide, corundum, covellite, crocoite, cuprite, danaite,digenite, embolite, enargite, euxenite, fayalite, ferberite,fergusonite, ferrous sulfide, franklinite, gahnite, galaxite, galena,geocronite, geothite, gersdorffite, greenockite, hausmmanite, hercynite,hessite, huebnerite, ilmenite, ilvaite, iodyrite, iridosmine, Jacobsite,Jamesonite, krennerite, larsenite, linarite, linnaeite, loellingite,magnesium oxide, manganese carbonate, manganite, manganosite, marcasite,marmatite, menaghinite, miargyrite, microlite, millerite, mimetite,minium, molybdenite, molybdenum (IV) oxide, molybdenum oxide, molybdenumtrioxide, monazite, nagyagite, niccolite, nickel oxide, pearceite,pentlandite, perovskite, petzite, phosgenite, phyromorphite, plagionite,polianite, polybasite, polycrase, powellite, proustite, psilomelane,pyrargyrite, pyrite, pyrochlore, pyrolusite, pyrrhotite, rammelsbergite,rutile, samarskite, scandium oxide, scheelite, semsyite, siegenite,skutterudite, smithsonite, spalerite, sperrylite, spessartite,sphalerite, stannite, stephanite, sternbergite, stibnite, stillwellite,stolzite, Stromeyerite, strontium oxide, sylvanite, tantalite,tennantite, tenorite, tephroite, tetrahedrite, thorianite, thorite, tindioxide, tin (II) oxide, titanium dioxide, turgite, uraninite,vanadinite, vanadium oxide, vanadium trioxide, vanadium (IV) oxide,vanadium (V) oxide, violarite, witherite, wolframite, wulfenite,wurtzite, xenotime, yttrium oxide, zinc carbonate, zincite, zinkenite,zircon, zirconium oxide, zirconium silicate, zinc oxide, and suitablecombinations thereof.

One of ordinary skill in the art should understand that some of themineral particles described herein may have health and/or environmentalconsiderations.

In some embodiments, the mineral particles described herein may beproduced by grinding methods, precipitation methods, melt form plasmamethods, etching bulk minerals, or any combination thereof, each whereapplicable based on, inter alia, the composition of the mineralparticle. It should be noted that the term “grinding” refers tomechanically breaking down the material into smaller pieces andencompasses milling, Raymond milling, roller milling, ball milling, andgrinding, machine grinding, crushing, and the like.

It should be noted that as used herein, the terms “median diameter” and“diameter distribution” refers to a weight median diameter and a weightdiameter distribution, respectively, wherein the diameter is based onthe largest dimension of the particles. For example, rod-like particleswould have diameter distributions and the like based on the length ofthe rod-like particles. As used herein, the term “median diameter”refers to a diameter distribution wherein 50% of the particles aresmaller than a given value.

In some embodiments, the mineral particles described herein produced bygrinding methods may have a median diameter ranging from a lower limitof about 100 nm, 250 nm, 500 nm, 1 micron, or 5 microns to an upperlimit of about 5000 microns, 2500 microns, 1000 microns, 500 microns,100 microns, 75 microns, 50 microns, 25 microns, or 10 microns, andwherein the median diameter may range from any lower limit to any upperlimit and encompasses any subset therebetween. One of ordinary skill inthe art should understand that larger particle sizes may be appropriatein some instances, e.g., mineral particles used in lost circulation orproppant compositions and methods. For example, the median diameter ofthe mineral particles may range from a lower limit of about 350 microns,500 microns, or 1 mm to an upper limit of about 15 mm, 10 mm, or 5 mm,and wherein the median diameter may range from any lower limit to anyupper limit and encompasses any subset therebetween.

Some embodiments of the present invention may involve precipitatingparticles from two or more salts in aqueous solutions so as to yield themineral particles described herein (or precursors to mineral particlesdescribed herein, e.g., particles that can be further calcined to yieldmineral particles described herein). For example, some embodiments ofthe present invention may involve precipitating manganese carbonate frommanganese (II) salts in aqueous solutions with alkali metal carbonatesso as to yield the mineral particles described herein that comprisemanganese carbonate. Examples of other salts that may be used inproducing precipitated mineral particles may include salts (e.g.,fluorides, chlorides, bromides, iodides, acetates, formates, citrates,sulfates, carbonates, hydroxides, phosphates, silicates, molybdates,tungstates, vanadates, titanates, chromates, and the like) of barium,bismuth, chromium, cobalt, copper, gold, iron, lead, nickel, strontium,tin, zinc, manganese, tungsten, aluminum, silver, cerium, magnesium,zirconium, titanium, calcium, antimony, lead, and the like, and anycombination thereof.

Some precipitation embodiments described herein may further involveadjusting the pH of the aqueous solution, adjusting the temperature ofthe aqueous solution, adding morphology modifiers to the aqueoussolution, adding aqueous-miscible organic liquids (e.g., an alcohol oracetone) to the aqueous solution, using capping agents (e.g., compoundswith moieties that interact with the crystal being formed so as to stop,slow, and/or direct growth of the crystal), and any combination thereof.The foregoing may be useful in regulating the average diameter, diameterdistribution, and shape of the mineral particles described herein. Forexample, increasing the pH and/or temperature may increase the averagediameter of the mineral particles described herein. In another example,additional polyelectrolytes may be used to synthesize mineral particleshaving a desired non-spherical shape.

In some embodiments, the particles produced by precipitation may becalcined to yield mineral particles described herein. Calcining may,inter alia, increase the mechanical properties (e.g., crush strength) ofthe mineral particles, yield a corresponding oxide (e.g., manganesecarbonate to manganese oxide, calcium carbonate to calcium oxide,bismuth carbonate to bismuth oxycarbonate or bismuth oxide, zirconiumhydroxide to zirconium oxide, or magnesium hydroxide to magnesiumoxide), or any combination thereof.

Examples of mineral particles that can be produced with precipitationmethods (optionally including calcining steps) may include, but are notlimited to, AgI, AgCl, AgBr, AgCuS, AgS, Ag₂S, Al₂O₃, AsSb, AuTe₂,BaCO₃, BaSO₄, BaCrO₄, BaO, BeO, BiOCl, (BiO)₂CO₃, BiO₃, Bi₂S₃, Bi₂O₃,CaO, CaF₂, CaWO₄, CaCO₃, (Ca,Mg)CO₃, CdS, CdTe, Ce₂O₃, CoAsS, Cr₂O₃,CuO, Cu₂O, CuS, Cu₂S, CuS₂, Cu₉S₅, CuFeS₂, Cu₅FeS₄, CuS.Co₂S₃,Fe²⁺Al₂O₄, Fe₂SiO₄, FeWO₄, FeAs₂, FeAsS, FeS, FeS₂, FeCO₃, Fe₂O₃,α-Fe₂O₃, α-FeO(OH), Fe₃O₄, FeTiO₃, HgS, Hg₂Cl₂, MgO, MnCO₃, Mn₂S, MnWO₄,MnO, MnO₂, Mn₂O₃, Mn₃O₄, Mn₂O₇, MnO(OH), CaMoO₄, MoS₂, MoO₂, MoO₃, NbO₄,NiO, NiAs₂, NiAs, NiAsS, NiS, PbTe, PbSO₄, PbCrO₄, PbWO₄, PbCO₃,(PbCl)₂CO₃, Pb²⁺ ₂Pb⁴⁺O₄, Sb₂SnO₅, Sc₂O₃, SnO, SnO₂, SrO, SrCO₃, SrSO₄,TiO₂, UO₂, V₂O₃, VO₂, V₂O₅, VaO, Y₂O₃, YPO₄, ZnCO₃, ZnO, ZnFe₂O₄,ZnAl₂O₄, ZnS, ZrSiO₄, ZrO₂, ZrSiO₄, and any combination thereof indiscrete domains and/or a substantially homogeneous domain.

In some embodiments, combination of more than one salt may be used toform precipitated particles with two or more of the foregoingprecipitates in substantially homogeneous domain. For example, strontiumand barium salts may be utilized in forming precipitated particles thatcomprise (Ba,Sr)SO₄ or (Ba,Sr)CO₃. In another example, barium salts maybe used in forming precipitated particles that comprise Ba(SO₄,CrO₄).Examples of other substantially homogeneous domains may include, but arenot limited to, suitable mixtures of barium, strontium, calcium, zinc,iron, cobalt, manganese, lead, tin, and the like, and any combinationthereof in the form of sulfates, carbonates, hydroxide, oxides,sulfides, chromates and the like, and any combination thereof.

Some embodiments may involve forming precipitated mineral particles withdiscrete domains that comprise at least one of the foregoingprecipitates. For example, a calcium carbonate particle may be formed byprecipitation and then barium salts added so as to precipitate bariumcarbonate on at least a portion of the surface of the calcium carbonateprecipitated particle. In another example, a higher specific gravitycomposition like those comprising bismuth may be precipitated and then adifferent composition precipitated thereon. Precipitating a secondcomposition on a first composition may allow for the first compositionto be formed with a desired shape and the second composition to increasethe specific gravity of the particle, which may allow for a desiredhigher specific gravity particle with a desired shape that may bedifficult to achieve otherwise. In another example, the higher specificgravity particle may be the first composition and the second compositionprecipitated thereon may enable linking of the particles or reduce theabrasiveness of the particles (described further herein).

In some embodiments, the mineral particles produced by precipitation maybe calcined to yield precipitated particles described herein. Calciningmay, inter alia, increase the mechanical properties (e.g., crushstrength) of the precipitated particles, yield a corresponding oxide(e.g., manganese carbonate to manganese oxide, calcium carbonate tocalcium oxide, bismuth carbonate to bismuth oxycarbonate or bismuthoxide, zirconium hydroxide to zirconium oxide, or magnesium hydroxide tomagnesium oxide), or any combination thereof.

In some embodiments, the precipitated mineral particles described hereinmay be shaped as spherical, ovular, substantially spherical,substantially ovular, discus, platelet, flake, toroidal (such asdonut-shaped), dendritic, acicular, spiked with a substantiallyspherical or ovular shape (such as a sea urchin), spiked with a discusor platelet shape, rod-like, fibrous (such as high-aspect ratio shapes),polygonal (such as cubic or pyramidal), faceted (such as the shape ofcrystals), star or floral shaped (such as a tripod or tetrapod whererods or the like extend from a central point), or any hybrid thereof(e.g., a dumbbell-shape). For example, spherical, ovular, substantiallyspherical, and substantially ovular-shaped precipitated mineralparticles may be useful in producing wellbore fluids that are lessabrasive to wellbore tools and/or decrease viscosity as compared toground mineral particles. In another example, platelet, flake, acicular,spiked with a discus or platelet shape, rod-like, and fibrous-shapedprecipitated mineral particles may be useful in producing wellborefluids with less sag and/or greater viscosity as compared to groundmineral particles.

In some embodiments, the precipitated mineral particles described hereinmay have a median diameter ranging from a lower limit of about 5 nm, 10nm, 20 nm, 50 nm, 100 nm, 250 nm, 500 nm, or 1 micron to an upper limitof about 100 microns, 50 microns, 25 microns, 10 microns, 5 microns, 1micron, or 750 nm, and wherein the median diameter may range from anylower limit to any upper limit and encompasses any subset therebetween.One of ordinary skill in the art should understand that precipitationmethods may be used to yield larger sizes of mineral particles that aremillimeters or larger in size. For example, precipitated mineralparticles having a median diameter of about 1-10 mm may be used asproppants or lost circulation materials.

In some embodiments, the precipitated particles may be ground to achievea desired size and/or shape. Methods that involve precipitation and thengrinding may advantageously allow for production of higher purityprecipitated particles as compared to particles produced by grindingbulk minerals. Further, such methods may allow for reduced cost whilemaintaining high purity as compared to some precipitation methods withsteps to control particle size. In some instances, larger precipitatedparticles may be directly added to a mined mineral and undergo the samegrinding process such that the ground product may have a higher puritythan the mineral alone. For example, large particles of barium sulfatemay formed by precipitation and added to mined barite with high levelsof contaminants (e.g., greater than 15% sand) such that the groundproduct is higher purity, which yields a less abrasive, higher specificgravity weighting agent that is of greater value in the industry.

In some embodiments, the conditions under which the precipitatedparticles are formed may be manipulated so as to assist in controllingor directing the characteristics of the precipitated particles (e.g.,shape, median diameter, diameter distribution, narrow diameterdistribution, density, hardness, and the like). Examples of conditionsthat can be manipulated may include, but are not limited to, pH,temperature, chemical composition of morphology modifiers, concentrationof morphology modifiers, concentration of the salts used in theproduction of the precipitated particles, and the like, and anycombination thereof. For example, increasing the pH and/or temperaturemay increase the median diameter of the precipitated particles. As usedherein, the term “morphology modifiers” refers to chemicals that areused during the formation of precipitated particles that effect thecharacteristics of the precipitated particles. Examples of morphologymodifiers may include, but are not limited to, polymers, surfactants,electrolytes, hydrogen peroxide, silicates and other similar inorganicmaterials, aqueous-miscible organic liquids, and the like, and anycombination thereof.

Additional examples of precipitation methods to produce at least some ofthe mineral particles described herein are disclosed in US PatentApplication No. 2014/0209386 filed the same day as the presentapplication, the entirety of which is incorporated herein by reference.

In some embodiments, the wellbore additives and/or the wellbore fluidsmay comprise the mineral particles described herein having a multimodaldiameter distribution (e.g., bimodal, trimodal, and so on). In someembodiments, the wellbore additives and/or the wellbore fluids maycomprise the mineral particles described herein having a multimodaldiameter distribution such that at least one mode has an averagediameter (or peak diameter) ranging from a lower limit of about 5 nm, 10nm, 20 nm, 50 nm, 100 nm, 250 nm, 500 nm, or 1 micron to an upper limitof about 50 microns, 10 microns, 5 microns, 1 micron, or 500 nm and atleast one mode has an average diameter ranging from a lower limit ofabout 10 microns, 25 microns, 50 microns, or 100 microns to an upperlimit of about 5000 microns, 2500 microns, 1000 microns, 500 microns,100 microns, or 50 microns, and wherein each mode may range from anycorresponding lower limit to any corresponding upper limit such that atleast two distinct modes are present and each range encompasses anycorresponding subset therebetween. By way of nonlimiting example, FIGS.1A-B illustrate appropriate multimodal diameter distributions for use inwellbore fluids. FIG. 1A illustrates a bimodal diameter distributionwith a first mode average diameter of about 1 micron and a second modeaverage diameter of about 25 microns. FIG. 1B illustrates a trimodaldiameter distribution with a first mode average diameter of about 5microns, a second mode average diameter of about 50 microns, and a thirdmode average diameter of about 90 microns.

In some embodiments, the mode(s) of a diameter distribution mayindependently be considered to have a narrow diameter distribution. Thatis, at least one mode of a diameter distribution (including monomodal)may have a standard deviation of about 2% or less of the peak diameterfor the given mode (e.g., about 0.1% to about 2% or any subsettherebetween). In some embodiments, precipitation methods may beadvantageously employed to achieve narrow diameter distributions ofmineral particles described herein.

In some embodiments, the mineral particles described herein may have acoating on at least a portion of the surface of the mineral particles.As used herein, the term “coating,” and the like, does not imply anyparticular degree of coating on the particle. In particular, the terms“coat” or “coating” do not imply 100% coverage by the coating on theparticle. Further, a coating may, in some embodiments, be covalentlyand/or noncovalently associate with the mineral particles describedherein.

In some embodiments, a coating suitable for use in conjunction with themineral particles described herein may include, but are not limited to,polymers, surfactants, and any combination thereof. Coatings may, insome embodiments, assist in the suspension of the mineral particlesand/or the compatibility of the mineral particles with a wellbore fluidand/or wellbore operation. For example, a coating like an alkyl aminemay, in some embodiments, associate with the surface of the mineralparticles so as to render the mineral particle more hydrophobic, whichmay enhance the suspendability of the mineral particles in oil-basedfluids.

In some embodiments, a coating may be applied during production of themineral particles described herein. For example, grinding productionmethods may, in some embodiments, be conducted in the presence ofpolymers, surfactants, or the like suitable for use as a coating.Additionally, in some embodiments, precipitation production methods maybe conducted in the presence of polymers, surfactants, or the likesuitable for use as a coating. One skilled in the art with the benefitof this disclosure should understand that including polymers,surfactants, or the like in a production method of the mineral particlesdescribed herein should be chosen so as not to significantly impact theproduction in a negative manner.

Polymers suitable for use in conjunction with the coated mineralparticles described herein may, in some embodiments, have a molecularweight ranging from a lower limit of about 10,000 g/mol, 25,000 g/mol,100,000 g/mol, or 250,000 g/mol to an upper limit of about 2,000,000g/mol, 1,000,000 g/mol, 500,000 g/mol, or 250,000 g/mol, and wherein themolecular weight may range from any lower limit to any upper limit andencompasses any subset therebetween. Examples of polymers suitable foruse in conjunction with the coated mineral particles described hereinmay, in some embodiments, include, but are not limited to, homopolymersor copolymers of monomers selected from the group comprising: acrylicacid, itaconic acid, maleic acid or anhydride, hydroxypropyl acrylatevinylsulphonic acid, acrylamido 2-propane sulphonic acid, acrylamide,methacrylamide, hydrolyzed acrylamide, styrene sulphonic acid, acrylicphosphate esters, methyl vinyl ether, vinyl acetate, stearylmethacrylate, butylacrylate, vinyl pyrrolidone, glycols (ethyleneglycol, propylene glycol, and butylene glycol), and the like, saltsthereof where appropriate, any derivative thereof, and any combinationthereof. Examples of commercially available polymers may includePluronic® surfactants (polyethylene oxide-polypropyleneoxide-polyethylene oxide triblock polymers, available from BASF),Tetronic® surfactants (tetra-functional block copolymers based onethylene oxide and propylene oxide, available from BASF), and the like,and any combination thereof.

Examples of surfactants suitable for use in conjunction with the coatedmineral particles described herein may, in some embodiments, include,but are not limited to, oleic acid, monobasic fatty acids, polybasicfatty acids, alkylbenzene sulfonic acids, alkane sulfonic acids, linearalpha-olefin sulfonic acid, phospholipids, betaines, and the like, saltsthereof where appropriate, any derivative thereof, and any combinationthereof. Examples of commercially available surfactants may includeBrij® surfactants (ethoxylated fatty alcohols, available fromSigma-Aldrich), Triton® surfactants (ethoxylated fatty alkylphenols,available from Sigma-Aldrich), and the like, and any combinationthereof.

In some embodiments, coatings may comprise consolidating agents thatgenerally comprise any compound that is capable of minimizingparticulate migration, which may be suitable for methods andcompositions relating to proppant packs, gravel packs, and the like.Suitable consolidating agents may include, but are not limited to,non-aqueous tackifying agents, aqueous tackifying agents, emulsifiedtackifying agents, silyl-modified polyamide compounds, resins,crosslinkable aqueous polymer compositions, polymerizable organicmonomer compositions, consolidating agent emulsions, zeta-potentialmodifying aggregating compositions, silicon-based resins, and binders.Combinations and/or derivatives of these also may be suitable.Nonlimiting examples of suitable non-aqueous tackifying agents may befound in U.S. Pat. Nos. 7,392,847, 7,350,579, 5,853,048; 5,839,510; and5,833,000, the entire disclosures of which are herein incorporated byreference. Nonlimiting examples of suitable aqueous tackifying agentsmay be found in U.S. Pat. Nos. 8,076,271, 7,131,491, 5,249,627 and4,670,501, the entire disclosures of which are herein incorporated byreference. Nonlimiting examples of suitable crosslinkable aqueouspolymer compositions may be found in U.S. Patent Application PublicationNo. 2010/0160187 and U.S. Pat. No. 8,136,595 the entire disclosures ofwhich are herein incorporated by reference. Nonlimiting examples ofsuitable silyl-modified polyamide compounds may be found in U.S. Pat.No. 6,439,309 entitled the entire disclosure of which is hereinincorporated by reference. Nonlimiting examples of suitable resins maybe found in U.S. Pat. Nos. 7,673,686; 7,153,575; 6,677,426; 6,582,819;6,311,773; and 4,585,064 as well as U.S. Patent Application PublicationNo. 2008/0006405 and U.S. Pat. No. 8,261,833, the entire disclosures ofwhich are herein incorporated by reference. Nonlimiting examples ofsuitable polymerizable organic monomer compositions may be found in U.S.Pat. No. 7,819,192, the entire disclosure of which is hereinincorporated by reference. Nonlimiting examples of suitableconsolidating agent emulsions may be found in U.S. Patent ApplicationPublication No. 2007/0289781 the entire disclosure of which is hereinincorporated by reference. Nonlimiting examples of suitablezeta-potential modifying aggregating compositions may be found in U.S.Pat. Nos. 7,956,017 and 7,392,847, the entire disclosures of which areherein incorporated by reference. Nonlimiting examples of suitablesilicon-based resins may be found in Application Publication Nos.2011/0098394, 2010/0179281, and U.S. Pat. Nos. 8,168,739 and 8,261,833,the entire disclosures of which are herein incorporated by reference.Nonlimiting examples of suitable binders may be found in U.S. Pat. Nos.8,003,579; 7,825,074; and 6,287,639, as well as U.S. Patent ApplicationPublication No. 2011/0039737, the entire disclosures of which are hereinincorporated by reference. It is within the ability of one skilled inthe art, with the benefit of this disclosure, to determine the type andamount of consolidating agent to include in the methods of the presentinvention to achieve the desired results.

II. Characteristics and Capabilities of Wellbore Fluids ComprisingMineral Particles Described Herein

In some embodiments, the wellbore fluids described herein may comprise abase fluid and the mineral particles described herein. Generally, themineral particles described herein may be useful as weighting agents soas to adjust the density of a wellbore fluid described herein. Further,in some embodiments, the mineral particles may serve other functions asdescribed further herein.

II.a. Density

Traditionally, weighting agents have consisted essentially of a singlemineral, most commonly barite (sometimes with up to 21% sandcontamination), with a monomodal diameter distribution. Given thereduced quality of barite and availability of other minerals around theworld, the mineral particles described herein (individually or incombination) may, in some embodiments, be included in the wellboreadditives and/or the wellbore fluids as a barite substitute weightingagent or a barite augmenting weighting agent.

In some embodiments, the wellbore additives and/or the wellbore fluidsmay comprise the mineral particles described herein so as to achieve adesired density of the wellbore fluid. In some embodiments, the wellborefluids described herein may have a density between a lower limit ofabout 7 pounds per gallon (“ppg”), 9 ppg, 12 ppg, 15 ppg, or 22 ppg toan upper limit of about 50 ppg, 40 ppg, 30 ppg, 22 ppg, 20 ppg, or 17ppg, and wherein the density of the wellbore fluid may range from anylower limit to any upper limit and encompasses any subset therebetween.One of ordinary skill in the art should understand that the ability toachieve a desired density of the wellbore fluid while maintaining afluid that can be pumped may depend on, inter alia, the composition andspecific gravity of the mineral particles, the shape of the mineralparticles, the concentration of the mineral particles, and the like, andany combination thereof. For example, wellbore fluids having a densityof about 25 ppg or higher may be achieved with mineral particles havinga specific gravity of about 7 or greater and having a shape ofspherical, substantially spherical, ovular, substantially ovular, or ahybrid thereof so as to allow for the fluid to be pumpable. In anotherexample, wellbore fluids having a density of about 30 ppg or less may beachieved with precipitated particles having a specific gravity of about7 or greater and having a larger variety of shapes, including discus.

While the plurality of mineral particles described herein (e.g., thoselisted in Section I) may be useful in modifying the density of awellbore fluid, in some preferred embodiments, achieving a desireddensity may utilize the mineral particles described herein that compriseat least one of rhodochrosite, tenorite, awaruite, albandite, bismuthoxychloride, fluorite, manganese carbonate, manganese (II) oxide,manganese (II,III) oxide, manganese (III) oxide, manganese (IV) oxide,manganese (VII) oxide, spalerite, strontianite, tenorite, zinccarbonate, zinc oxide, and any combination thereof.

In some embodiments, a mixture of two or more types of mineral particlesdescribed herein having a multiparticle specific gravity useful forachieving a desired density. As used herein, the term “multiparticlespecific gravity” refers to the calculated specific gravity from FormulaI.multiparticle specific gravity=vol % A*sg _(A)+vol %B*sg _(B)+ . . . vol% n*sg _(n)  Formula I

-   -   wherein vol % is the volume percent of particle relative to the        total volume of the particles used as weighting agent, sg is the        specific gravity of the particle, A is the first particle, B is        the second particle, and n is the n^(th) particle

In some embodiments, the wellbore additives and/or the wellbore fluidsmay comprise a mixture of mineral particles described herein having amultiparticle specific gravity ranging from a lower limit of about 3, 4,4.5, 5, or 5.5 to an upper limit of about 20, 15, 10, 9, 8, or 7, andwherein the multiparticle specific gravity may range from any lowerlimit to any upper limit and encompasses any subset therebetween. One ofordinary skill in the art with the benefit of this disclosure shouldunderstand that when specific gravity is referred to in combination withmultiple mineral particles, specific gravity refers to the multiparticlespecific gravity.

In some embodiments, when using two or more precipitated particles withdifferent specific gravities to produce a homogeneous wellbore fluid,the size and shape of each of the precipitated particles may be tailoredso as to minimize separation of the precipitated particles, which maylead to a wellbore fluid with a striated density profile. For example, afirst precipitated particle with a discus or platelet shape may impedethe settling of a second precipitated particle that has a high settlingor migration rate (e.g., a higher specific gravity, spherical particle).

II.b. Abrasiveness

In some embodiments, the properties of the mineral particles describedherein may be tailored to mitigate the abrasion of wellbore tools (e.g.,pumps, drill bits, drill string, and a casing) as compared to comparableAPI grade barite (i.e., a comparable wellbore fluid having the samedensity and/or sag as the wellbore fluid comprising the mineralparticles), which may prolong the life of the wellbore tools. It shouldbe noted that the term “wellbore tools” encompasses tools suitable foruse in conjunction with wellbore operations, including tools that areused outside of the wellbore, e.g., pumps, shakers, and the like.Abrasion can be measured by the ASTM G75-07 and is reported as a MillerNumber or a SAR Number.

Suitable mineral particles can be those with properties tailored tomitigate abrasion, which may include, but are not limited to, hardness(e.g., a Mohs hardness of less than about 5), size (e.g., mediandiameter less than about 400 nm or mode of a multimodal distributionhaving an peak diameter less than about 400 nm), shape (e.g., particleshapes with higher sphericity like spherical, substantially spherical,ovular, substantially ovular, and the like), coatings (e.g., thickerand/or elastic coatings that minimize physical interactions between themineral portion of the particle and the wellbore tool), and the like,and any combination thereof. For example, wellbore additives and/or thewellbore fluids may comprise substantially spherical awaruite particleswith a median diameter less than about 400 nm and manganese carbonateparticles, which have a Mohs hardness less than about 5.

In some embodiments, wellbore additives and/or the wellbore fluids maycomprise at least one of the foregoing suitable mineral particles thatmitigate abrasion of wellbore tools in combination with at least onemineral particle described herein that may not mitigate abrasion ofwellbore tools. For example, wellbore additives and/or the wellborefluids that are less abrasive than the comparable wellbore fluid (i.e.,comprising API-grade barite and having the same density and/or sag) maycomprise manganese carbonate particles with a median diameter less thanabout 400 nm and awaruite particles with a median diameter greater thanabout 500 nm.

Examples of mineral particles with a Mohs hardness of less than about 5may include BaSO₄, CaCO₃, (Ca,Mg)CO₃, FeCO₃, FeTiO₃, (Fe,Mg)SiO₄, SrSO₄,MnO(OH), barite, calcium carbonate, dolomite, siderite, manganesedioxide, AgI, AgCl, AgBr, AgS, Ag₂S, Ag₃SbS₃, AgSbS₂, AgSbS₂, Ag₅SbS₄,(AgFe₂S₃), Ag₃AsS₃, Ag₃AsS₃, Cu(Ag,Cu)₆Ag₉As₂S₁₁,[(Ag,Cu)₆(Sb,As)₂S₇][Ag₉CuS₄], Ag₃AuTe₂, (Ag,Au)Te₂, Ag₂Te, Al₂SiO₅,AsSb, AuTe₂, BaCO₃, BaO, Bi, BiOCl, Bi₂S₃, Bi₂O₃, CaF₂, CaWO₄, CdS,CdTe, Co⁺²Co⁺³ ₂S₄, Cu, CuO, Cu₂O, CuS, Cu₂S, CuS₂, Cu₉S₅, CuFeS₂,Cu₅FeS₄, Cu₃ASO₄(OH)₃, Cu₃AsS₄, Cu₁₂As₄S₁₃, Cu₂(ASO₄)(OH), CuPb₁₃Sb₇S₂₄,CuSiO₃.H₂O, Fe₂SiO₄, FeWO₄, FeS, Fe_((1-x))S (wherein x=0 to 0.2),(Fe,Mn)WO₄, (Mn,Fe,Mg)(Al,Fe)₂O₄, (YFe³⁺Fe²⁺U,Th,Ca)₂(Nb,Ta)₂O₈, HgS,MnCO₃, Mn₂S, MnWO₄, (Na_(0.3)Ca_(0.1)K_(0.1))(Mn⁴⁺,Mn³⁺)₂O₄.1.5H₂O,Ca(Mn³⁺,Fe³⁺)₁₄SiO₂₄, CaMoO₄, MoS₂, (Y,Ca,Ce,U,Th)(Nb,Ta,Ti)₂O₆,(Ce,La)PO₄, (Ce,La)CO₃F, (Y,Ce)CO₃F, NiS, PbTe, PbSO₄, PbCrO₄, PbWO₄,PbSiO₃, PbCO₃, PbCO₂CO₃, Pb₅(PO₄)₃Cl, Pb₅(ASO₄)₃Cl, Pb²⁺ ₂Pb⁴⁺O₄,Pb₅Au(Te,Sb)₄S₅₋₈, Pb₅Sb₈S₁₇, PbS, Pb₉Sb₈S₂₁, Pb₅Sb₄S₁₁, Pb₄FeSb₆S₁₄,PbCu[(OH)₂|SO₄], PbCuSbS₃, (Cu,Fe)₁₂Sb₄S₁₃, Sb₂S₃, (Sb³⁺,Sb⁵⁺)O₄,Cu₂FeSnS₄, SrCO₃, (Th,U)SiO₄, Pb₅(VO₄)₃Cl, YPO₄, ZnCO₃, ZnO, ZnCO₃, ZnO,(Zn_((1-x))Fe_((x))S), (Zn,Fe)S, acanthite, allemontite, altaite,anglesite, antimony sulfide, argentite, barium carbonate, bastnaesite,birnessite, bismite, bismuth, bismuth oxychloride, bismuth sulfide,bismuth sulfide, bismuth (III) oxide, bornite, boulangerite, bournonite,bromyrite, cadimum sulfide, calayerite, celestine, cerargyrite,cerussite, cervantite, chalcocite, chalcopyrite, cinnabar, clinoclase,copper, copper oxide, copper sulfide, covellite, crocoite, cuprite,digenite, embolite, enargite, ferberite, ferrous sulfide, galena,greenockite, hessite, huebnerite, ilmenite, iodyrite, Jamesonite,krennerite, linarite, manganese carbonate, manganite, marmatite,menaghinite, miargyrite, millerite, mimetite, minium, molybdenite,monazite, nagyagite, pearceite, pentlandite, petzite, phosgenite,phyromorphite, plagionite, polybasite, proustite, pyrargyrite,pyrrhotite, scheelite, semsyite, siderite, smithsonite, sphalerite,stannite, stephanite, sternbergite, stibnite, stolzite, sylvanite,tennantite, tenorite, tetrahedrite, thorite, vanadinite, witherite,wolframite, wulfenite, wurtzite, xenotime, zinc carbonate, zincite, zincoxide, and suitable combinations thereof.

II.c. Sag Control

Particles (e.g., weighting agents, proppants, and cement particles) inwellbore fluids can settle from the wellbore fluid therein, which is acondition known as “sag.” As used herein, the term “sag” refers to aninhomogeneity in density of a fluid in a wellbore, e.g., along thelength of a wellbore and/or the diameter of a deviated wellbores. Insome instances, sag can cause to portions of the wellbore fluid to be atan insufficient density to stabilize the wellbore and other portions ofthe wellbore fluid to have increased density. Unstabilized portions ofthe wellbore can lead to wellbore collapse and/or pressure buildups thatcause blowouts. Increased density can cause wellbore damage (e.g.,undesired fracturing of the wellbore), which may show up as pressureincreases or decreases when changing from static to flow conditions ofthe fluid which can cause higher than desired pressures downhole.

In some embodiments, the mineral particles described herein may besized, shaped, or otherwise treated (e.g., coated) so as to mitigate sagin wellbore fluids. The size may, inter alia, provide for the formationof a stable suspension that exhibit low viscosity under shear. Further,the specific gravity of the mineral particles may further allow for suchmineral particles to provide for a desired density of the wellbore fluidwhile mitigating sag of these mineral particles or other particlestherein.

Sag control can be measured by analyzing density changes in anundisturbed sample of wellbore fluid over time at a typical wellboretemperature (e.g., about 300° F.) and an elevated pressure (e.g., about5,000 psi to about 10,000 psi). For example, the mineral particlesdescribed herein that provide effective sag control may, in someembodiments, yield wellbore fluids having a change in density of lessthan about 1 ppg (e.g., about 0.5 ppg change or less including no changein density) when comparing a fluid's original density to the fluid'sdensity at the bottom of a sample having been undisturbed for a givenamount of time. In some embodiments, the mineral particles describedherein may provide sag control (i.e., a density change of less thanabout 1 ppg) over a time ranging from a lower limit of about 10 hours,24 hours, 36 hours, or 48 hours to an upper limit of about 120 hours, 96hours, 72 hours, or 48 hours, and wherein the sag control timeframe ofthe wellbore fluid may range from any lower limit to any upper limit andencompasses any subset therebetween.

In some embodiments, the properties of the mineral particles describedherein may be tailored to achieve sag control. Properties of the mineralparticles that can be tailored to achieve sag control may include, butare not limited to, size (e.g., median diameter of about 2 microns orless or at least one mode of a multimodal distribution having such apeak diameter of about 2 microns or less), shape (e.g., particle shapeswith lower sphericity like discus, platelet, flake, ligamental,acicular, spiked with a substantially spherical or ovular shape, spikedwith a discus or platelet shape, fibrous, toroidal, and the like),coatings, linking (described further herein), and the like, and anycombination thereof.

While the plurality of mineral particles described herein (e.g., thoselisted in Section I) may be useful in achieving sag control of awellbore fluid, in some preferred embodiments, sag control may utilizethe mineral particles described herein that comprise at least one ofrhodochrosite, tenorite, awaruite, albandite, bismuth oxychloride,fluorite, manganese carbonate, manganese (II) oxide, manganese (II,III)oxide, manganese (III) oxide, manganese (IV) oxide, manganese (VII)oxide, spalerite, strontianite, tenorite, zinc carbonate, zinc oxide,and any combination thereof.

In some embodiments, when using two or more mineral particles withdifferent specific gravities to produce a homogeneous wellbore fluid,the size and shape of each of the mineral particles may be tailored soas to minimize separation of the mineral particles, which may lead to awellbore fluid with a striated density profile. For example, a firstmineral particle with a discus or platelet shape may impede the settlingof a second mineral particle that has a high settling or migration rate(e.g., a higher specific gravity, spherical particle).

II.d. Viscosity

At least some of the mineral particles described herein may, in someembodiments, be capable of being linked by linking agents. Linking ofmineral particles may allow for increasing the viscosity of the wellborefluid or forming a solid mass described further herein. One skilled inthe art with the benefit of this disclosure should recognize that, interalia, the composition of the mineral particles described herein maydetermine if the mineral particles are suitable for being linked and towhat degree they can be linked.

Examples of linking agents suitable for use in conjunction with thewellbore additives and/or the wellbore fluids may, in some embodiments,include, but are not limited to, eugenol, guaiacol, methyl guaiacol,salicyladehyde, salicyladimine, salicylic acid, sodium salicylate,acetyl salicylic acid, methyl salicylic acid, methyl acetylsalicylicacid, anthranilic acid, acetyl anthranilic acid, vanillin, derivatized1,2-dihydroxybenzene (catechol), derivatized or unsubstituted phthalicacid, ortho-phenylenediamine, ortho-aminophenol,ortho-hydroxyphenylacetic acid, alkylsilanes, esters, ethers, and thelike, and any combination thereof. Additionally polymers of theforegoing examples, or suitable derivatives thereof, may used as linkingagents. For example, vinyl derivatives of the foregoing examples may beused in synthesizing a polymer or copolymer suitable for use as alinking agents. In another example, carboxylated derivates of theforegoing examples may be used in derivatizing a polyamine to yieldsuitable linking agents. Additional examples may include, but are notlimited to, compounds (including polymers and lower molecular weightmolecules) having at least two silane moieties, ester moieties, ethermoieties, sulfide moieties, amine moieties, and the like, and anycombination thereof.

Viscosity increases from linking with linking agents may, in someembodiments, yield wellbore fluids that remain pumpable, wellbore fluidsthat are non-pumpable, or hardened masses. One skilled in the art withthe benefit of this disclosure should understand that the extent of theviscosity increase may depend on, inter alia, the composition of themineral particles described herein, the composition of the linkingagents, the relative concentration of the mineral particles and thelinking agents, intended use, additional components in the wellborefluid, and any combination thereof.

In some embodiments, the increase in viscosity may yield a hardenedmass. As used herein, the term “hardened mass” is used to indicate acomposition that has transitioned from a liquid-state to a substantiallysolid-state, but does not imply a size or function of the hardened mass.For example, a hardened mass may be a plug that spans cross-sectionalarea of the wellbore or a composition that has filled a crack in anexisting hardened mass (e.g., a cement sheath) and solidified. In someembodiments, a hardened mass may be rigid or relatively pliable. In someembodiments, such a hardened mass may be permeable (e.g., 1 Da to about100 mDa) or substantially non-permeable (e.g., about 100 mDa or less).

In some embodiments, the wellbore additives and/or the wellbore fluidsmay comprise linking agents at an amount ranging from a lower limit ofabout 0.1%, 0.5%, or 1% by weight of the mineral particles to an upperlimit of about 10%, 5%, or 1% by weight of the mineral particles.

While a plurality of mineral particles described herein may be usefulfor linking, in some preferred embodiments, linking methods andcompositions may utilize the mineral particles described herein thatcomprise at least one of Al₂O₃, Al₂SiO₅, BaCO₃, BaO, BeO, (BiO)₂CO₃,BiO₃, Bi₂O₃, CaO, CaCO₃, (Ca,Mg)CO₃, CdS, CdTe, Ce₂O₃, (Fe,Mg)Cr₂O₄,Cr₂O₃, CuO, Cu₂O, Cu₂(AsO₄)(OH), CuSiO₃.H₂O, Fe₃Al₂(SiO₄)₃, Fe²⁺Al₂O₄,Fe₂SiO₄, FeCO₃, Fe₂O₃, α-Fe₂O₃, α-FeO(OH), Fe₃O₄, FeTiO₃, (Fe,Mg)SiO₄,(Mn,Fe,Mg)(Al,Fe)₂O₄, CaFe²⁺ ₂Fe³⁺Si₂O₇O(OH),(YFe³⁺Fe²⁺U,Th,Ca)₂(Nb,Ta)₂O₈, MgO, MnCO₃, Mn₂SiO₄, Mn(II)₃Al₂(SiO₄)₃,(Na_(0.3)Ca_(0.1)K_(0.1))(Mn⁴⁺,Mn³⁺)₂O₄.1.5H₂O, (Mn,Fe)₂O₃,(Mn²⁺,Fe²⁺,Mg)(Fe³⁺,Mn³⁺)₂O₄, (Mn²⁺,Mn³⁺)₆[O₈|SiO₄],Ca(Mn³⁺,Fe³⁺)₁₄SiO₂₄, Ba(Mn²⁺)(Mn⁴⁺)₈O₁₆(OH)₄, CaMoO₄, MoO₂, MoO₃, NbO₄,(Na,Ca)₂Nb₂O₆(OH,F), (Y,Ca,Ce,U,Th)(Nb,Ta,Ti)₂O₆,(Y,Ca,Ce,U,Th)(Ti,Nb,Ta)₂O₆, (Fe,Mn)(Ta,Nb)₂O₆, (Ce,La, Ca)BSiO₅,(Ce,La)CO₃F, (Y,Ce)CO₃F, MnO, MnO₂, Mn₂O₃, Mn₃O₄, Mn₂O₇, MnO(OH),(Mn²⁺,Mn³⁺)₂O₄, NiO, NiAs₂, NiAs, NiAsS, Ni_(x)Fe (x=2-3), (Ni,Co)₃S₄,PbSiO₃, PbCO₃, (PbCl)₂CO₃, Pb²⁺ ₂Pb⁴⁺O₄, PbCu[(OH)₂|SO₄], (Sb³⁺,Sb⁵⁺)O₄,Sb₂SnO₅, Sc₂O₃, SnO, SnO₂, Cu₂FeSnS₄, SrO, SrSO₄, SrCO₃, (Na,Ca)₂Ta₂O₆(O,OH,F), ThO₂, (Th,U)SiO₄, TiO₂, UO₂, V₂O₃, VO₂, V₂O₅,Pb₅(VO₄)₃Cl, VaO, Y₂O₃, ZnCO₃, ZnO, ZnFe₂O₄, ZnAl₂O₄, ZrSiO₄, ZrO₂,ZrSiO₄, allemontite, altaite, aluminum oxide, anglesite, tin oxide,antimony trioxide, barium carbonate, barium oxide, bastnaesite,beryllium oxide, birnessite, bismite, bismuth oxycarbonates, bismuthoxychloride, bismuth trioxide, bismuth (III) oxide, bixbyite,bournonite, braunite, cadimum sulfide, cadimum telluride, calayerite,calcium oxide, calcium carbonate, cassiterite, cerium oxide, cerussite,chromium oxide, clinoclase, columbite, copper, copper oxide, corundum,crocoite, cuprite, dolomite, euxenite, fergusonite, franklinite,gahnite, geothite, greenockite, hausmmanite, hematite, hercynite,hessite, ilvaite, Jacobsite, magnesium oxide, manganese carbonate,manganite, manganosite, magnetite, manganese dioxide, manganese (IV)oxide, manganese oxide, manganese tetraoxide, manganese (II) oxide,manganese (III) oxide, microlite, minium, molybdenum (IV) oxide,molybdenum oxide, molybdenum trioxide, nickel oxide, pearceite,phosgenite, psilomelane, pyrochlore, pyrolusite, rutile, scandium oxide,siderite, smithsonite, spessartite, stillwellite, stolzite, strontiumoxide, tantalite, tenorite, tephroite, thorianite, thorite, tin dioxide,tin (II) oxide, titanium dioxide, uraninite, vanadium oxide, vanadiumtrioxide, vanadium (IV) oxide, vanadium (V) oxide, witherite, wulfenite,yttrium oxide, zinc carbonate, zincite, zircon, zirconium oxide,zirconium silicate, zinc oxide, and suitable combinations thereof.Mineral particles not suitable for linking may include, but are notlimited to, CaF₂, CuS, CuFeS₂, FeS, FeS₂, HgS, Hg₂Cl₂, NiAs, NiAsS, PbS,and (Zn,Fe)S.

II.e. Compressive Strength

In some embodiments, the mineral particles described herein mayadvantageously have a higher unconfined compressive strength (e.g.,about 1200 psi or greater) that allow for load-bearing applications(e.g., proppant applications). In some embodiments, the mineralparticles described herein may advantageously have a moderate to highunconfined compressive strength (e.g., about 500 psi or greater) thatallow for implementation in applications like cements, wellborestrengthening additives, and gravel packs. The unconfined compressivestrength of a mineral particle may depend on, inter alia, thecomposition of the mineral particle, the shape of the mineral particle,additional processing steps in producing the mineral particle (e.g.,calcining after precipitation), and the like, and any combinationthereof.

While a plurality of mineral particles described herein may have atleast moderate compressive strength, in some preferred embodiments, suchmineral particles may comprise at least one of CaCO₃, (Ca,Mg)CO₃, FeCO₃,Fe₂O₃, α-Fe₂O₃, α-FeO(OH), Fe₃O₄, FeTiO₃, (Fe,Mg)SiO₄, MnO, MnO₂, Mn₂O₃,Mn₃O₄, Mn₂O₇, MnO(OH), (Mn²⁺,Mn³⁺)₂O₄, calcium carbonate, hematite,siderite, magnetite, manganese dioxide, manganese (IV) oxide, manganeseoxide, manganese tetraoxide, manganese (II) oxide, manganese (III)oxide, Al₂O₃, Al₂SiO₅, CaF₂, CaWO₄, CuO, Cu₂O, CuS, Cu₂S, CuS₂, Cu₉S₅,CuFeS₂, Cu₅FeS₄, CuS.Co₂S₃, CuSiO₃.H₂O, Fe₃Al₂(SiO₄)₃, Fe²⁺Al₂O₄,Fe₂SiO₄, FeWO₄, FeS, FeS₂, Fe_((1-x))S (wherein x=0 to 0.2), (Fe,Ni)₉S₈,Fe²⁺Ni₂ ³⁺S₄, (Fe,Mn)WO₄, (Mn,Fe,Mg)(Al,Fe)₂O₄, CaFe⁺ ₂Fe³⁺Si₂O₇O(OH),MnCO₃, Mn₂S, Mn₂SiO₄, MnWO₄, Mn(II)₃Al₂(SiO₄)₃,(Na_(0.3)Ca_(0.1)K_(0.1))(Mn⁴⁺,Mn³⁺)₂O₄.1.5H₂O, (Mn,Fe)₂O₃,(Mn²⁺,Fe²⁺,Mg)(Fe³⁺,Mn³⁺)₂O₄, (Mn²⁺,Mn³⁺)₆[O₈|SiO₄],Ca(Mn³⁺,Fe³⁺)₁₄SiO₂₄, CaMoO₄, MoO₂, MoO₃, NiO, Ni_(x)Fe (x=2-3),(Ni,Co)₃S₄, NiS, SnO, SnO₂, Cu₂FeSnS₄, TiO₂, ZnCO₃, ZnO, ZnFe₂O₄,ZnAl₂O₄, ZnCO₃, ZnS, ZnO, (Zn_((1-x))Fe_((x))S), (Zn,Fe)S, ZrSiO₄, ZrO₂,ZrSiO₄, alabandite, alamandite, aluminum oxide, andalusite, awaruite,birnessite, bixbyite, bornite, braunite, bravoite, calcium oxide,carrollite, cassiterite, chalcopyrite, copper oxide, copper sulfide,corundum, covellite, digenite, ferberite, ferrous sulfide, franklinite,gahnite, geothite, hausmmanite, hercynite, huebnerite, ilmenite,ilvaite, Jacobsite, larsenite, manganese carbonate, manganite,manganosite, marcasite, marmatite, millerite, molybdenum oxide,molybdenum trioxide, nickel oxide, pentlandite, pyrite, pyrolusite,pyrrhotite, rutile, scheelite, siegenite, smithsonite, spalerite,spessartite, sphalerite, tenorite, tephroite, tin dioxide, tin (II)oxide, titanium dioxide, wolframite, wurtzite, zinc carbonate, zincite,zircon, zirconium oxide, zirconium silicate, zinc oxide, and suitablecombinations thereof.

II.f. Degradability

At least some of the mineral particles described herein may, in someembodiments, be at least partially degradable. As used herein, the term“degradable” refers to a material being capable of reduced in size byheterogeneous degradation (or bulk erosion) and homogeneous degradation(or surface erosion), and any stage of degradation in between these two.This degradation can be a result of, inter alia, a chemical or thermalreaction, for example, dissolution by an acidic fluid. One skilled inthe art with the benefit of this disclosure should recognize that, interalia, the composition of the mineral particles described herein maydetermine if the mineral particles are degradable and to what extentthey are degradable.

While a plurality of mineral particles described herein may bedegradable, in some preferred embodiments, degradable mineral particlesmay comprise at least one of BaCO₃, (BiO)₂CO₃, CaWO₄, CaCO₃, CuO, FeCO₃,(Ce,La)CO₃F, (Y,Ce)CO₃F, PbCO₃, (PbCl)₂CO₃, SrCO₃, ZnCO₃, aragonite,bastnaesite, barium carbonate, bismuth oxycarbonate, calcium carbonate,cerussite, copper oxide, manganese carbonate, phosgenite, rhodochrosite,scheelite, siderite, smithsonite, strontianite, witherite, zinccarbonate, and suitable combinations thereof. Examples of mineralparticles described herein that may not be degradable may, in someembodiments, include, but are not limited to, mineral particles thatcomprise aluminum oxide, antimony sulfide, antimony tin oxide, antimonytrioxide, bismuth (III) oxide, cadmium sulfide, cadmium telluride,copper, copper sulfide, ferrous sulfide, magnesium oxide, magnetite,manganese dioxide, pyrite, strontium oxide, zirconium silicate, zincoxide, and any combination thereof.

Degradation of the minerals described herein may advantageously be usedin a plurality of wellbore operations, e.g., cleanup operations (e.g.,in removing a filter cake or plug from a lost circulation operation) andcementing operations (e.g., in enhancing the permeability of a cementplug to allow for fluid to flow therethrough while still providingstructural strength). Additionally, degradation may be advantageous inreducing the viscosity of a fluid by degrading mineral particles thatcontribute to the viscosity (e.g., by shape and/or by linking).

Examples of degradation agents that may be useful in at least partiallydegrading mineral particles described herein may, in some embodiments,include, but are not limited to, acid sources (e.g., inorganic acids,organic acid, and polymers that degrade into acids like polylacticacid), alkaline sources (e.g., bases), and oxidizers (e.g., peroxidecompounds, permanganate compounds, and hexavalent chromium compounds).

In some embodiments, the mineral particles described herein may bechosen so as to degrade over a desired amount of time, which may bedependent on, inter alia, particle size, particle shape, wellboretemperature, and mineral particle composition. For example, calciumcarbonate rather than lead carbonate may be utilized, in someembodiments, when for faster degradation. In another example, manganesecarbonate may, in some embodiments, be chosen for slower degradation incolder wellbore environments and faster degradation in hotter wellboreenvironments.

II.g. Recovery and Recycling

In some embodiments, the mineral particles described herein may berecovered from the wellbore fluids and/or wellbore additives andrecycled for another use. It should be noted that the term “recovery”relative to mineral particles described herein encompasses collection ofthe mineral particles from the wellbore fluids and the physical orchemical portions thereof (e.g., collecting mineral particles that havebeen partially degraded or collecting the chemicals resultant fromdegradation like salt or ions). As used herein, the term “recycle”refers encompasses both using the mineral particles again withoutsignificant physical or chemical modification (e.g., adding to anotherwellbore fluid after cleaning or applying a coating) and significantlychanging the physical or chemical nature of the mineral particles (e.g.,melting, grinding to change the diameter distribution, dissolving andprecipitating new mineral particles, and the like).

Referring now to FIG. 2, some embodiments may involve recovering themineral particles described herein so as to yield a recovered mineralproduct (e.g., the mineral particles, the mineral particles partiallydegraded, and/or the degradation products of the mineral particles),optionally grading the recovered mineral product, and recycling therecovered mineral product. Recovery of mineral particles describedherein may, in some embodiments, involve at least one of: filtering,magnetically extracting, centrifuging, sludging, chelating, linking,dissolving, chemically degrading, supercritical fluid extraction, andthe like, and any combination thereof.

For example, some of the mineral particles described herein (e.g.,magnetite, awaruite, chromite, ilmenite, and siderite) have a magneticsusceptibility that allows for the use of magnetic separation,optionally in combination with other methods, to extract the mineralparticles from a wellbore fluid and/or wellbore additive to yield arecovered mineral product. In some embodiments, the recovered mineralproduct may be used in another wellbore fluid and/or wellbore additive.

In some embodiments, recovery of the mineral particles described hereinmay involve degrading the mineral particles while they resided thewellbore and collecting the resultant fluid (i.e., the recovered mineralproduct), which may, in some embodiments, be processed so as toconcentrate of the chemicals resultant from the degradation. Forexample, an acid may be used to degrade rhodochrosite that resides inthe wellbore so as to yield a fluid that comprises manganese ions. Sucha fluid, depending on the additional components of the fluid, may thenbe concentrated, neutralized, and then used for precipitation ofmanganese carbonate mineral particles for use in additional wellboreoperations.

The recovered mineral product (e.g., the mineral particles, the mineralparticles partially degraded, and/or the degradation products of themineral particles) may, in some embodiments, be in the solid form (e.g.,a plurality of particles or a hardened mass), liquid form (e.g., asludge, a slurry, or a low viscosity fluid), or the like.

One skilled in the art with the benefit of this disclosure shouldunderstand that the recovery methods and resultant recovered mineralproduct for each mineral particle described herein may, in someembodiments, depend on, inter alia, the composition of the mineralparticles, the composition of the wellbore fluid and/or wellboreadditive (e.g., the additional components therein), the viscosity of thewellbore fluid, and the like, and any combination thereof.

Recycling of the recovered mineral product described herein may, in someembodiments, involve using the recovered mineral product as-is (e.g.,producing a wellbore fluid described herein with the recovered mineralproduct), processing the recovered mineral product so as to yieldmineral particles described herein for use of wellbore applications(e.g., grinding or precipitating to form mineral particles describedherein), or using the recovered mineral product and methods andprocesses that produce other materials (e.g., smelting to form steel,processing to extract precious metals, and the like).

Recycling of a recovered mineral product described herein may, in someembodiments, be on-site or off-site. For example, some embodiments mayinvolve magnetically extracting mineral particles (e.g., awaruite)on-site so as to yield a recovered mineral product and recyclingrecovered mineral product comprising the mineral particles into anotherwellbore fluid. In another example, some embodiments may involvedegrading mineral particles (e.g., rhodochrosite or tenorite) into arecovered mineral product comprises the corresponding dissolved saltsand recycling the recovered mineral product to yield precipitatedmineral particles described herein, which may, in some embodiments, beperformed on-site or at a suitable processing facility.

Recycling the mineral particles described herein may, in someembodiments, involve grading of the recovered mineral product. As usedherein, the term “grading” refers to assessing the quality of therecovered mineral product relative to the desired recycling method.Grading may, in some embodiments, be achieved by gravimetry, atomicspectroscopy, mass spectroscopy, Auger electron spectroscopy, X-rayphotoelectron spectroscopy, and the like.

In some embodiments, the recycling of the mineral particles describedherein may involve methods that concentrates of the mineral particles(or components thereof) in the recovered mineral product, cleans themineral particles (or components thereof) (e.g., washing or burning awayorganic matter), and the like, each of which may be used to enhance thegrading value of the recovered mineral product. For example, inrecycling methods that involve processing the recovered mineral productto achieve other materials (e.g., smelting rhodochrosite in theprocesses for making cast iron or steel), the recovered mineral productmay be burned to remove organic material, which may increase the gradingvalue and, consequently, the intrinsic value of the recovered mineralproduct.

II.h. Other Properties and/or Capabilities

Some of the mineral particles described herein may have othercharacteristics that may impart properties and/or capabilities to awellbore fluid and/or wellbore additive described herein. Thesecharacteristics may advantageously be utilized to further reduce oreliminate additional components in wellbore fluids and/or wellboreadditives without reducing or eliminating the properties and/orcapabilities thereof.

For example, the antimicrobial properties of tenorite, copper oxide, andthe like may advantageously allow for the weighting agent to also serveas, inter alia, an antimicrobial additive. Antimicrobial agents may beuseful in maintaining a clean wellbore and mitigating microbial growthduring transportation of a wellbore additive.

II.i. Combining Properties and/or Capabilities

As described further herein, it may be advantageous to utilize mineralparticles that allow for adjusting the density of a wellbore fluid andproviding at least one of the other properties and/or capabilitiesdescribed herein.

For example, in some embodiments, the wellbore additives and/or thewellbore fluids may comprise mineral particles described herein having amedian diameter of about 2 microns or less, a Mohs hardness of about 5or less, and a specific gravity of about 2.6 or greater, includingcombination of any subset of the foregoing ranges (e.g., mineralparticles having a median diameter between about 250 nm and about 1micron, a Mohs hardness of about 2 to about 4, and a specific gravity ofabout 5 to about 20) so as to provide for a wellbore fluid with adesired density, sag control, and abrasion mitigation.

In some embodiments, wellbore additives and/or wellbore fluids may beproduced on-site, on-the-fly, or off-site. For example, if a well siteis near a mine or facility that produced mineral particles describedherein, the wellbore additives and/or wellbore fluids may be producedon-site. In another example, the wellbore fluid tailorability that themineral particles described herein may further provide for on-the-flymodification of wellbore fluids so as to respond to the conditions ofthe wellbore and/or events that occur in the wellbore.

The mineral particles described herein may be present in the wellborefluid in an amount sufficient for a particular application. In certainembodiments, the mineral particles described herein may be present in awellbore fluid in an amount up to about 70% by volume of the wellborefluid (v %) (e.g., about 5%, about 15%, about 20%, about 25%, about 30%,about 35%, about 40%, about 45%, about 50%, about 55%, about 60%, about65%, etc.). In certain embodiments, the mineral particles describedherein may be present in the wellbore fluid in an amount of 10 v % toabout 40 v %.

In some embodiments, the wellbore additives may comprise the mineralparticles described herein and optionally further comprise otherparticles and/or additional components suitable for use in a specificwellbore operation (e.g., proppants and cement particles as describedfurther herein). Wellbore additives may, in some embodiments, be drypowder or gravel, a liquid with a high concentration of the mineralparticles described herein (e.g., a slurry), and the like.

As described herein, in some embodiments, it may be advantageous toinclude a combination of types of mineral particles described herein soas to achieve a wellbore fluid with desired properties and/orcapabilities. Distinctions between types of mineral particles may, insome embodiments, be defined by at least one of mineral composition,production method, average diameter, diameter distribution, presence orabsence of coating, coating composition, and the like, and anycombination thereof. As such, achieving homogeneous mixtures of drywellbore additives may be aided by inclusion of a dry lubricant tofacilitate homogeneous mixing and flowability. Examples of dry lubricantmay, in some embodiments, include, but are not limited to, molybdenumdisulfide, graphite, boron nitride, tungsten disulfide,polytetrafluoroethylene particles, bismuth sulfide, bismuth oxychloride,and the like, and any combination thereof. In some embodiments, a drylubricant may advantageously have a specific gravity greater than about2.6 (e.g., molybdenum disulfide, tungsten disulfide, bismuth sulfide,and bismuth oxychloride) so as contribute to the density of theresultant wellbore fluid.

Examples of base fluids suitable for use in conjunction with thewellbore fluids may, in some embodiments, include, but are not limitedto, oil-based fluids, aqueous-based fluids, aqueous-miscible fluids,water-in-oil emulsions, or oil-in-water emulsions. Suitable oil-basedfluids may include alkanes, olefins, aromatic organic compounds, cyclicalkanes, paraffins, diesel fluids, mineral oils, desulfurizedhydrogenated kerosenes, and any combination thereof. Suitableaqueous-based fluids may include fresh water, saltwater (e.g., watercontaining one or more salts dissolved therein), brine (e.g., saturatedsalt water), seawater, and any combination thereof. Suitableaqueous-miscible fluids may include, but not be limited to, alcohols,e.g., methanol, ethanol, n-propanol, isopropanol, n-butanol,sec-butanol, isobutanol, and t-butanol; glycerins; glycols, e.g.,polyglycols, propylene glycol, and ethylene glycol; polyglycol amines;polyols; any derivative thereof; any in combination with salts, e.g.,sodium chloride, calcium chloride, calcium bromide, zinc bromide,potassium carbonate, sodium formate, potassium formate, cesium formate,sodium acetate, potassium acetate, calcium acetate, ammonium acetate,ammonium chloride, ammonium bromide, sodium nitrate, potassium nitrate,ammonium nitrate, ammonium sulfate, calcium nitrate, sodium carbonate,and potassium carbonate; any in combination with an aqueous-based fluid;and any combination thereof.

Suitable water-in-oil emulsions, also known as invert emulsions, mayhave an oil-to-water ratio from a lower limit of greater than about30:70, 40:60, 50:50, 55:45, 60:40, 65:35, 70:30, 75:25, or 80:20 to anupper limit of less than about 100:0, 95:5, 90:10, 85:15, 80:20, 75:25,70:30, or 65:35 by volume in the base fluid, where the amount may rangefrom any lower limit to any upper limit and encompass any subsettherebetween. Examples of suitable invert emulsions include thosedisclosed in U.S. Pat. No. 5,905,061 entitled “Invert Emulsion FluidsSuitable for Drilling” filed on May 23, 1997, U.S. Pat. No. 5,977,031entitled “Ester Based Invert Emulsion Drilling Fluids and Muds HavingNegative Alkalinity” filed on Aug. 8, 1998, U.S. Pat. No. 6,828,279entitled “Biodegradable Surfactant for Invert Emulsion Drilling Fluid”filed on Aug. 10, 2001, U.S. Pat. No. 7,534,745 entitled “Gelled InvertEmulsion Compositions Comprising Polyvalent Metal Salts of anOrganophosphonic Acid Ester or an Organophosphinic Acid and Methods ofUse and Manufacture” filed on May 5, 2004, U.S. Pat. No. 7,645,723entitled “Method of Drilling Using Invert Emulsion Drilling Fluids”filed on Aug. 15, 2007, and U.S. Pat. No. 7,696,131 entitled “DieselOil-Based Invert Emulsion Drilling Fluids and Methods of DrillingBoreholes” filed on Jul. 5, 2007, each of which are incorporated hereinby reference in their entirety. It should be noted that for water-in-oiland oil-in-water emulsions, any mixture of the above may be usedincluding the water being and/or comprising an aqueous-miscible fluid.

In some embodiments, the wellbore fluids described herein may be foamed.As used herein, the term “foam” refers to a two-phase composition havinga continuous liquid phase and a discontinuous gas phase. In someembodiments, the wellbore fluids may comprise a base fluid, the mineralparticles described herein, a gas, and a foaming agent.

Examples of gases may include, but are not limited to, nitrogen, carbondioxide, air, methane, helium, argon, and any combination thereof. Oneskilled in the art, with the benefit of this disclosure, shouldunderstand the benefit of each gas. By way of nonlimiting example,carbon dioxide foams may have deeper well capability than nitrogen foamsbecause carbon dioxide emulsions have greater density than nitrogen gasfoams so that the surface pumping pressure required to reach acorresponding depth is lower with carbon dioxide than with nitrogen.Moreover, the higher density may impart greater particle transportcapability, up to about 12 lb of particles per gal of wellbore fluid.

In some embodiments, the quality of a wellbore fluid that is foamed mayrange from a lower limit of about 5%, 10%, 25%, 40%, 50%, 60%, or 70%gas volume to an upper limit of about 95%, 90%, 80%, 75%, 60%, or 50%gas volume, and wherein the quality may range from any lower limit toany upper limit and encompasses any subset therebetween. Mostpreferably, the wellbore fluid that is foamed may have a foam qualityfrom about 85% to about 95%, or about 90% to about 95%.

Examples of foaming agents may include, but are not limited to, cationicfoaming agents, anionic foaming agents, amphoteric foaming agents,nonionic foaming agents, or any combination thereof. Nonlimitingexamples of suitable foaming agents may, in some embodiments, include,but are not limited to, surfactants like betaines, sulfated orsulfonated alkoxylates, alkyl quarternary amines, alkoxylated linearalcohols, alkyl sulfonates, alkyl aryl sulfonates, C₁₀-C₂₀ alkyldiphenylether sulfonates, polyethylene glycols, ethers of alkylated phenol,sodium dodecylsulfate, alpha olefin sulfonates such as sodium dodecanesulfonate, trimethyl hexadecyl ammonium bromide, and the like, anyderivative thereof, or any combination thereof. Foaming agents may beincluded in foamed treatment fluids at concentrations ranging typicallyfrom about 0.05% to about 2% of the liquid component by weight (e.g.,from about 0.5 to about 20 gallons per 1000 gallons of liquid).

In some embodiments, the wellbore additives and/or the wellbore fluidsdescribed herein may optionally further comprise additional components,e.g., filler particles, salts, inert solids, fluid loss control agents,emulsifiers, dispersion aids, corrosion inhibitors, emulsion thinners,emulsion thickeners, viscosifying agents, gelling agents, crosslinkingagents, surfactants, cement particulates, proppants, gravelparticulates, lost circulation materials, pH control additives,breakers, defoaming agents, biocides, stabilizers, scale inhibitors, gashydrate inhibitors, oxidizers, reducers, friction reducers, claystabilizing agents, set accelerators, set retarders, and combinationsthereof. One skilled in the art with the benefit of this disclosureshould understand the appropriate composition, concentration, andcombination of individual additional components that may be included inthe wellbore additives and/or the wellbore fluids that comprise themineral particles described herein.

The wellbore additives and/or the wellbore fluids described herein maybe used in a plurality of wellbore operations. Examples wellboreoperations may, in some embodiments, include, but are not limited to,drilling operations, managed-pressure drilling operations, dual-gradientdrilling, tripping operations, logging operations, lost circulationoperations, stimulation operations, sand control operations, completionoperations, acidizing operations, scale inhibiting operations,water-blocking operations, clay stabilizer operations, fracturingoperations, gravel packing operations, wellbore strengtheningoperations, and sag control operations. The wellbore additives and/orthe wellbore fluids described herein may, in some embodiments, be usedin full-scale operations or pills. As used herein, a “pill” is a type ofrelatively small volume of specially prepared wellbore fluid placed orcirculated in the wellbore.

III. Wellbore Operations using Wellbore Fluids Comprising MineralParticles Described Herein

As discussed throughout, the mineral particles described herein may beuseful in a variety of wellbore fluids and/or wellbore additives. Thewellbore fluid tailorability that the mineral particles described hereinmay, in some embodiments, be particularly advantageous in some wellboreoperations, e.g., fracturing operations, cementing operations, and thelike. Further, as mentioned above, the wellbore fluid tailorability mayprovide for on-the-fly modification of wellbore fluids so as to respondto the conditions of the wellbore and/or events that occur in thewellbore. Such conditions may be determined prior to introduction of thewellbore fluid into the wellbore (e.g., using logging information andlithological theory) and/or actually encountered during use of thewellbore fluid (e.g., while circulating the wellbore fluid). Anon-the-fly modification to at least one of the wellbore fluid propertiesor capabilities (e.g., through alteration to the identity orconcentration of the mineral particles in the wellbore fluid) can bemade to optimize a wellbore operation (e.g., encountering an unknownlost circulation or thief zone).

Examples of wellbore operations (full-scale and/or pill operations) thatcan employ the mineral particles and wellbore fluids described hereinmay, in some embodiments, include, but are not limited to, drillingoperations, lost circulation operations, stimulation operations, sandcontrol operations, completion operations, acidizing operations, scaleinhibiting operations, water-blocking operations, clay stabilizeroperations, fracturing operations, frac-packing operations, gravelpacking operations, wellbore strengthening operations, and sag controloperations.

Some embodiments of the present invention may further include producinghydrocarbons from at least a portion of a subterranean formation,wherein the subterranean formation has been treated with a wellborefluid described herein. In some embodiments, hydrocarbons may beproduced from the portion of the subterranean formation having beentreated with a wellbore fluid described herein (e.g., a fracturingfluid) or from a second portion of the subterranean formation having notbeen treated with the wellbore fluid (e.g., as described herein relativeto a fluid flow control operation).

It should be noted that as used herein terms like “linkable mineralparticle,” “degradable mineral particle,” and the like are used inexamples to indicated at least one property of the mineral particle anddo not necessarily preclude mineral particles with other properties,e.g., a “linkable mineral particle” may also be degradable andrecyclable or a “sag control mineral particle” may also be linkable anddegradable.

III.a. Cementing Operations

In some embodiments, the wellbore additives and/or the wellbore fluidsdescribed herein may be used in cementing operations. As used herein,the term “cementing operations” refers to operations where a compositionis placed in a wellbore and/or a subterranean formation and sets thereinto form a hardened mass, which encompasses hydraulic cements,construction cements, linked mineral particles described herein, andsome polymeric compositions that set (e.g., polymers like epoxies andlatexes).

Examples of cementing operations that may utilize the mineral particlesdescribed herein may, in some embodiments, include, but are not limitedto, primary cementing operations (e.g., forming cement sheaths in awellbore annulus or forming wellbore plugs for zonal isolation or fluiddiversion) and remedial cementing operations (e.g., squeeze operations,repairing and/or sealing microannuli and/or cracks in a hardened mass,or forming plugs). In cementing operations, a plurality of fluids areoften utilized including, but not limited to, cementing fluids(sometimes referred to as settable compositions), spacer fluids, anddisplacement fluids. For example, a cementing operation may utilize, inorder, (1) a first spacer fluid, (2) a cementing fluid, optionally (3) asecond spacer fluid, and (4) a displacement fluid, each of which mayindependently be a wellbore fluid comprising mineral particles describedherein.

In some embodiments, cementing operations may utilize a plurality offluids in order such that each subsequent fluid has a higher densitythan the previous fluid. Achieving the desired density for a wellborefluid in a cementing operation may, in some embodiments, involve the useof mineral particles described herein. Further, as described herein, themineral particles utilized in such wellbore fluids may be chosen toachieve other properties and/or capabilities in the wellbore fluids. Itshould be noted that in a cementing operation when a plurality ofwellbore fluids are used, each wellbore fluid may be independentlydesigned with mineral particles described herein and do not necessarilyrequire the use of the same mineral particle in each of the wellborefluids or the use of a mineral particle described herein in all of thewellbore fluids. For example, the first spacer fluid may includefluorite, the cementing fluid may include manganese oxide, and thesecond spacer may include tenorite.

One of ordinary skill in the art should understand the plurality of usesof the mineral particles described herein and the appropriateincorporation into the wellbore fluids suitable for use in conjunctionwith cementing operations. For example, cementing fluids, spacer fluids,and/or displacement fluids, may comprise mineral particles describedherein so as to achieve a desired density, a desired level of sagcontrol, and/or a desired viscosity. In another example, linkablemineral particles may be included in the cementing fluids and utilizedso as to yield hardened masses that comprise linked mineral particles.In yet another example, degradable mineral particles may be included inthe cementing fluids and utilized so as to yield hardened masses thatthat can be at least partially degraded. Further, depending on thecomposition of the mineral particle, combinations of the foregoingexamples may be appropriate, e.g., mineral particles comprisingrhodochrosite may be useful in cementing fluids to achieve a desireddensity and a desired level of sag control, to link in forming thehardened mass, and to degrade for increasing the permeability of thehardened mass.

In some embodiments, cementing operations may involve forming hardenedmasses that comprise at least one of: linked mineral particles describedherein, cement particles, and any combination thereof. As describedabove, the term “hardened mass,” as used herein, refers to a compositionthat has transitioned from a liquid-state to a substantially solid-stateand does not imply a size or function of the hardened mass. For example,a hardened mass may be a plug that spans cross-sectional area of thewellbore or a composition that has filled a crack in an existinghardened mass (e.g., a cement sheath) and solidified.

In some embodiments, wellbore fluids (e.g., settable compositions)suitable for use in conjunction with cementing operations may comprise abase fluid and linkable mineral particles and optionally furthercomprise cement particles.

In some embodiments in which linkable mineral particles described hereinare used, the linking agents may be introduced into the wellbore in apreceding wellbore fluid, the same wellbore fluid, and/or a subsequentwellbore fluid as the settable composition. For example, a firstwellbore fluid that comprises linkable mineral particles describedherein may be introduced into a wellbore and subsequently a secondwellbore fluid that comprises the appropriate linking agents may beintroduced into the wellbore so as to contact at least some of thelinkable mineral particles in the first wellbore fluid. The linkingagent should then link the mineral particles therein, thus forming ahardened mass comprising linked mineral particles. In other examples,some embodiments may involve introducing a wellbore fluid that comprisesa base fluid, suitable linkable mineral particles described herein, andsuitable linking agents into a wellbore penetrating a subterraneanformation and allowing the linking agents to link the linkable mineralparticles so as to yield a hardened mass that comprises linked mineralparticles.

The amount of linkable mineral particles described herein included inwellbore fluids (e.g., settable compositions) so as to achieve hardenedmasses may depend on, inter alia, the composition and amount of theoptional cement particles, the composition and amount of the optionaladditional components (e.g., fillers described further herein), thecomposition of the mineral particles, the average diameter of themineral particles, the diameter distribution of the mineral particles,the dimensions and volume of the set cement, and the like, and anycombination thereof.

In some embodiments, the degradable mineral particles described herein(linkable or otherwise) may be included in wellbore fluids (e.g.,settable compositions) suitable for use in conjunction with cementingoperations described herein so as to allow for changing the permeabilityof the hardened mass produced therefrom. In some embodiments,degradation and/or dissolution of the mineral particles in a hardenedmass may be achieved by exposing the hardened mass to an acidictreatment fluid, a treatment fluid comprising an acid source, a basictreatment fluid, an oxidizing treatment fluid, and the like.

Change of the permeability of a hardened mass may be useful, in someembodiments, for converting a substantially impermeable hardened mass(e.g., having a permeability less than about 10⁻² milliDarcy) thatsubstantially blocks fluid flow to a permeable hardened mass that allowfluid to flow therethrough, for example, when alleviating zonalisolation from plugs and/or wellbore/subterranean formation separationfrom sheaths. The ability to convert a hardened mass from substantiallyimpermeable to permeable may, in some embodiments, advantageouslyeliminate the need to drill out plugs or perforate sheaths in order torestore a desired level of permeability.

In some embodiments, wellbore fluids (e.g., settable compositions)suitable for use in conjunction with cementing operations may comprise abase fluid, mineral particles described herein capable of linking, andmineral particles capable of degradation. In some embodiments, wellborefluids (e.g., settable compositions) suitable for use in conjunctionwith cementing operations may comprise a base fluid, cement particles,and degradable mineral particles and optionally further compriselinkable mineral particles. In some embodiments, the degradable mineralparticles may also be linkable.

In some embodiments, the hardened mass after degradation and/ordissolution of the degradable mineral particles therein may have apermeability ranging from a lower limit of about 10⁻¹ milliDarcy(“mDa”), 1 mDa, or mDa to an upper limit of about 1000 mDa, 100 mDa, or10 mDa, and wherein the permeability may range from any lower limit toany upper limit and encompasses any subset therebetween.

The amount of degradable mineral particles described herein included inwellbore fluids (e.g., settable compositions) suitable for use inconjunction with cementing operations so as to achieve hardened massescapable of changing permeability may depend on, inter alia, thecomposition and amount of the cement particles, the composition andamount of the optional additional components (e.g., fillers describedfurther herein), the composition of the degradable mineral particles,the average diameter of the degradable mineral particles, the diameterdistribution of the degradable mineral particles, the dimensions of theset cement, and the like, and any combination thereof.

In some embodiments, the cementing operations described herein mayinvolve the recovery and recycling the mineral particles describedherein. For example, after degradation of a portion of a hardened mass,the resultant fluid may be recovered and recycled according to anysuitable recovery and recycling method described herein suitable for usein conjunction with the mineral particles utilized. In another example,a spacer fluid or displacement fluid utilizing mineral particlesdescribed herein may be recovered and recycled according to any suitablerecovery and recycling method described herein suitable for use inconjunction with the mineral particles utilized.

Base fluids suitable for use in conjunction with wellbore fluidssuitable for use in conjunction with cementing operations (e.g., spacerfluids, settable compositions, and/or displacement fluids) may, in someembodiments, include any of the base fluids described herein in relationto wellbore fluids in general. In some embodiments where wellbore fluidscomprise cement particles, the base fluid may preferably comprise water.In some embodiments, wellbore fluids suitable for use in conjunctionwith cementing operations may be foamed as described herein in relationto wellbore fluids in general.

The base fluid may be present in the wellbore fluids suitable for use inconjunction with cementing operations in an amount sufficient to form apumpable slurry. In some embodiments, the wellbore fluids suitable foruse in conjunction with cementing operations may include base fluids inan amount ranging from a lower limit of about 30% by weight of cement(“bwoc”), 50% bwoc, or 100% bwoc to an upper limit of about 200% bwoc,150% bwoc, or 100% bwoc, and wherein the amount may range from any lowerlimit to any upper limit and encompasses any subset therebetween. Asused herein, the term “by weight of cement” refers to by weight of thecement and/or linkable mineral particles.

Examples of cement particles suitable for use in conjunction with thewellbore fluids and/or wellbore additives described herein may, in someembodiments, include, but are not limited to, hydraulic cements,Portland cement, gypsum cements, calcium phosphate cements, high aluminacontent cements, silica cements, high alkalinity cements, shale cements,acid/base cements, magnesia cements (e.g., Sorel cements), fly ashcements, zeolite cement systems, cement kiln dust, slag cements,micro-fine cements, epoxies, bentonites, latexes, and the like, anyderivative thereof, and any combination thereof.

In some embodiments, the wellbore fluids and/or wellbore additivesdescribed herein suitable for use in conjunction with cementingoperations may optionally further comprise additional componentsdescribed herein in relation to wellbore fluids in general. Examples ofpreferred additional components may, in some embodiments, include, butare not limited to, filler particles, salts, weighting agents, inertsolids, fluid loss control agents, emulsifiers, dispersion aids,corrosion inhibitors, emulsion thinners, emulsion thickeners,viscosifying agents, gelling agents, crosslinking agents, surfactants,cement particulates, proppants, gravel particulates, lost circulationmaterials, pH control additives, breakers, defoaming agents, biocides,stabilizers, scale inhibitors, gas hydrate inhibitors, oxidizers,reducers, friction reducers, clay stabilizing agents, set accelerators,set retarders, and combinations thereof.

In some embodiments, the hardened masses, the wellbore fluids (e.g.,settable compositions), and/or wellbore additives described hereinsuitable for use in conjunction with cementing operations may optionallyfurther comprise filler particles. Filler particles may, in someembodiments, be useful in tailoring the mechanical properties of thefinal set cement, e.g., some polymers and rubbers may allow for hardenedmasses that are more pliable than hardened masses without such polymersand rubbers. Examples of filler particles suitable for use inconjunction with the wellbore fluids and/or wellbore additives describedherein may, in some embodiments, include, but are not limited to, flyash, fume silica, hydrated lime, pozzolanic materials, sand, barite,calcium carbonate, ground marble, iron oxide, manganese oxide, glassbead, crushed glass, crushed drill cutting, ground vehicle tire, crushedrock, ground asphalt, crushed concrete, crushed cement, ilmenite,hematite, silica flour, fume silica, fly ash, elastomers, polymers,diatomaceous earth, a highly swellable clay mineral, nitrogen, air,fibers, natural rubber, acrylate butadiene rubber, polyacrylate rubber,isoprene rubber, chloroprene rubber, butyl rubber, brominated butylrubber, chlorinated butyl rubber, chlorinated polyethylene, neoprenerubber, styrene butadiene copolymer rubber, sulphonated polyethylene,ethylene acrylate rubber, epichlorohydrin ethylene oxide copolymer,ethylene propylene rubber, ethylene propylene diene terpolymer rubber,ethylene vinyl acetate copolymer, fluorosilicone rubber, siliconerubber, poly-2,2,1-bicycloheptene (polynorbornene), alkylstyrene,crosslinked substituted vinyl acrylate copolymer, nitrile rubber(butadiene acrylonitrile copolymer), hydrogenated nitrile rubber, fluororubber, perfluoro rubber, tetrafluoroethylene/propylene, starchpolyacrylate acid graft copolymer, polyvinyl alcohol cyclic acidanhydride graft copolymer, isobutylene maleic anhydride, acrylic acidtype polymer, vinylacetate-acrylate copolymer, polyethylene oxidepolymer, carboxymethyl cellulose polymer, starch-polyacrylonitrile graftcopolymer, polymethacrylate, polyacrylamide, and non-soluble acrylicpolymer, and the like, and any combination thereof.

In some embodiments, the wellbore fluids and/or wellbore additivesdescribed herein suitable for use in conjunction with cementingoperations may include filler particles in an amount ranging from alower limit of about 5% bwoc, 10% bwoc, 25% bwoc, or 50% bwoc to anupper limit of about 150% bwoc, 100% bwoc, or 50% bwoc, and wherein theamount may range from any lower limit to any upper limit and encompassesany subset therebetween.

III.b. Fracturing

In some embodiments, the wellbore additives and/or the wellbore fluidsdescribed herein may be used in fracturing operations. Fracturingoperations, in some embodiments, may involve introducing a firstwellbore fluid (e.g., pad fluid) into a subterranean formation at apressures sufficient to create or extend at least one fracture in thesubterranean formation and introducing a second wellbore fluid (e.g., aproppant slurry) into the subterranean formation so as to create aproppant pack in the at least one fracture. As used herein, a “proppantpack” refers to a collection of proppant particles in a fracture.

Advantageously, at least some of the proppant mineral particlesdescribed herein (e.g., those having an unconfined compressive strengthof about 1200 psi or greater) may, in some embodiments, allow fortailoring a proppant slurry to have a desired density with proppantmineral particles also being useful as proppant particles, therebyreducing the need for additional weighting agent and/or traditionalproppant particles (and associated costs) to achieve substantially thesame result. In some embodiments, the proppant mineral particlesdescribed herein may optionally be used in fracturing operations incombination with traditional proppant particles.

Examples of traditional proppant particles that may be suitable for usein conjunction with the mineral particles described herein may, in someembodiments, include, but are not limited to, sand, glass materials,polymer materials, polytetrafluoroethylene materials, nut shell pieces,cured resinous particulates comprising nut shell pieces, seed shellpieces, cured resinous particulates comprising seed shell pieces, fruitpit pieces, cured resinous particulates comprising fruit pit pieces,wood, composite particulates (e.g., particulates that may comprise abinder and a filler material wherein suitable filler materials includesilica, fumed carbon, carbon black, graphite, mica, titanium dioxide,meta-silicate, calcium silicate, kaolin, talc, zirconia, boron, fly ash,hollow glass microspheres, solid glass, and any combination thereof),and the like, and any combination thereof.

The proppant mineral particles described herein and/or traditionalproppant particles used in conjunction with fracturing operationsgenerally may have a median diameter ranging from a lower limit of about350 microns, 500 microns, or 1 mm to an upper limit of about 15 mm, 10mm, or 5 mm, and wherein the median diameter may range from any lowerlimit to any upper limit and encompasses any subset therebetween. Itshould be understood that fibrous materials, that may or may not be usedto bear the pressure of a closed fracture, may be included in certainembodiments of the present invention.

In some embodiments, the proppant mineral particles optionally incombination with the traditional proppant particles may be included inthe proppant slurries in an amount in the range of from about 0.5 poundsper gallon (“ppg”) to about 30 ppg of total proppant content by volumeof the fracturing fluid, and encompass any subset therebetween.

In some embodiments, the proppant mineral particles described herein mayfurther be useful for imparting the properties and/or capabilitiesdescribed herein in relation to wellbore fluids in general (e.g.,density, viscosity, sag control, degradation, and the like) to thewellbore fluids suitable for use in conjunction with fracturingoperations.

Some embodiments may involve exploiting the degradability of some of theproppant mineral particles described herein to change the permeabilityof a proppant pack. For example, some embodiments may involveintroducing a first wellbore fluid into at least a portion of asubterranean formation at a pressure sufficient to create or extend atleast one fracture in the subterranean formation; introducing a secondwellbore fluid that comprises a base fluid, a degradable mineralparticles described herein suitable for use as a proppant, and proppantparticles (e.g., traditional proppant particles and/or substantiallynon-degradable proppant mineral particles described herein) into thesubterranean formation so as to form a proppant pack in the at least onefracture; and contacting the proppant pack with a third wellbore fluidcomprising a degradation agent so as to increase the permeability of theproppant pack.

In some embodiments, the mineral particles described herein may be lesssuitable for use as proppant particles and may be utilized inconjunction with fracturing operations so as to achieve any combinationof the properties and/or capabilities described herein in relation towellbore fluids in general (e.g., density, viscosity, sag control,degradation, and the like). For example, mineral particles comprisingbismuth oxychloride may be useful in achieving a desired density and sagcontrol for wellbore fluids suitable for use in conjunction withfracturing operations.

In some embodiments, a proppant slurry may, in some embodiments,comprise a base fluid, traditional proppant particles, and mineralparticles that have a suitable diameter distribution to mitigate sag ofthe traditional proppant particles (e.g., a median diameter of about 2microns or less) at a concentration to achieve a desired density of thewellbore fluid. In some embodiments, such mineral particles may,depending on the composition, also be degradable (e.g., manganesecarbonate or tenorite), applicable as proppants (e.g., manganesecarbonate or awaruite), linkable (e.g., manganese carbonate ortenorite), or any combination thereof, thereby allowing for othercharacteristics of the proppant slurry to be tailored for the conditionsencountered in the wellbore and/or subterranean formation.

In some embodiments, the fracturing operations described herein mayinvolve the recovery and recycling the mineral particles describedherein. For example, after degradation of a portion of a proppant pack,the resultant fluid may be recovered and recycled according to anysuitable recovery and recycling method described herein suitable for usein conjunction with the mineral particles utilized.

Base fluids suitable for use in conjunction with wellbore fluidsdescribed herein suitable for use in conjunction with fracturingoperations may, in some embodiments, include any of the base fluidsdescribed above in relation to wellbore fluids in general. Further, insome embodiments, wellbore fluids described herein suitable for use inconjunction with fracturing operations may be foamed as described abovein relation to wellbore fluids in general.

In some embodiments, the wellbore fluids and/or wellbore additivesdescribed herein suitable for use in conjunction with fracturingoperations may optionally further comprise additional componentsdescribed herein in relation to wellbore fluids in general. Examples ofpreferred additional components may, in some embodiments, include, butare not limited to, filler particles, salts, weighting agents, inertsolids, fluid loss control agents, emulsifiers, dispersion aids,corrosion inhibitors, emulsion thinners, emulsion thickeners,viscosifying agents, gelling agents, crosslinking agents, surfactants,cement particulates, proppants, gravel particulates, lost circulationmaterials, pH control additives, breakers, defoaming agents, biocides,stabilizers, scale inhibitors, gas hydrate inhibitors, oxidizers,reducers, friction reducers, clay stabilizing agents, set accelerators,set retarders, and combinations thereof.

III.c. Fluid Flow Control

In some embodiments, the mineral particles described herein may beuseful in fluid flow control between a wellbore and the surroundingsubterranean formation. Controlling the flow of fluids between thewellbore and the subterranean formation can be especially important for,inter alia, maintaining the proper wellbore pressure (e.g., to mitigateblowouts), minimize loss of wellbore fluids (often expensive wellborefluids) into the subterranean formation, ensure proper placement of awellbore fluids (e.g., fluids comprising proppants), and the like.

In some embodiments, fluid flow control may be achieved by at least oneof the following mechanisms: bridging a fracture, reducing or blockingformation permeability, providing fluid loss control, sealing a rocksurface, sealing a thief zone, enabling fluid diversion, plugging avoid, controlling water production, and any combination thereof withinthe subterranean formation. In some embodiments, pores, voids,high-permeability porosity, and the like may be found in a subterraneanformation, e.g., in conjunction with a gravel pack within the wellbore,a borehole surface within the wellbore, a proppant pack within asubterranean formation, rock faces within a subterranean formation(including in fractures, microfractures, and the like), highpermeability channels, and the like, and any combination thereof. Forsimplicity, as used herein, unless otherwise specified, when referringto occurrences (e.g., fluid loss or fluid diversion) in or into asubterranean formation, each of the aforementioned situations/locationsare encompassed.

Fluid loss may be problematic in any number of subterranean operations,including drilling operations, fracturing operations, acidizingoperations, gravel-packing operations, wellbore clean-out operations,produced water reduction or elimination, and the like. In fracturingoperations, for example, fluid loss into the formation may result in areduction in fluid efficiency, such that the fracturing fluid cannotpropagate fracture formation as desired. Without being limited bytheory, the wellbore fluids described herein may, in some embodiments,lower the volume of a filtrate that passes through a filter medium. Thatis, the wellbore fluids described herein (e.g., the mineral particles,the mineral particles in combination with additional fluid components,and/or linked mineral particles) may block the pore throats and spacesthat would otherwise allow a fluid to leak out of a desired zone andinto an undesired zone. The wellbore fluids described herein (e.g., themineral particles, the mineral particles in combination with additionalfluid components, and/or linked mineral particles) may, in someembodiments, be used to control fluid loss by filling/bridging the porespaces, voids, and the like in subterranean formation, e.g., forming atype of filter cake that blocks the pore spaces at or near the boreholesurface to prevent fluid loss into the subterranean formation.

Fluid diversion is a similar approach to fluid loss control but strivesfor a somewhat different approach where a portion of the subterraneanformation is sealed off or rendered less permeable. By way of example,in order to divert a fluid from highly permeable portions of theformation into the less permeable portions of the formation, a volume ofa wellbore fluid may be pumped into the high permeability portion of theformation to partially or completely seal off that portion fromsubsequent fluid penetration. When being placed, a wellbore fluid willflow most readily into the portion of the formation having the largestpores, fissures, or vugs and, in some embodiments, deposit the mineralparticles therein, until that portion is bridged and sealed, thusdiverting the remaining and/or subsequent fluid to the next mostpermeable portion of the formation.

Some embodiments may involve introducing a first wellbore fluidcomprising the mineral particles described herein into a subterraneanformation; allowing the first wellbore fluid to penetrate into a portionof the subterranean formation in a sufficient amount so as to providefluid flow control (e.g., sealing, bridging, plugging, diversion, andthe like) within a first portion of the subterranean formation; andintroducing a second wellbore fluid (e.g., a pad fluid, a proppantslurry, a cementing fluid, or the like) into the subterranean formationsuch that the first wellbore fluid at least substantially blocks thesecond wellbore fluid from entering the first portion of thesubterranean formation (e.g., an area of fluid flow control thatcomprises the mineral particles).

Providing fluid flow control may, in some embodiments, be achieved withhigh density fluids (e.g., the first wellbore fluid having a higherdensity than the second wellbore fluid), viscosifying fluids optionallythrough the mineral particle linking (e.g., the first wellbore fluidhaving a higher viscosity than the second wellbore fluid), forminghardened masses (e.g., with the first wellbore fluid), and anycombination thereof.

In some embodiments, the mineral particles described herein may beutilized in the first and/or the second wellbore fluids so as to achieveconditions that allow for fluid flow control operations. For example,the first wellbore fluid may comprise first mineral particles (e.g.,comprising awaruite and/or tenorite) in a sufficient amount to yield thedesired density that is higher than the second wellbore fluid. In someembodiments, the second wellbore fluid may be useful in other operationslike fracturing operations or cementing operations.

In some embodiments, the mineral particles described herein may beutilized for achieving a desired viscosity so as to allow for fluid flowcontrol operations. In some embodiments, the mineral particles describedherein suitable for use in conjunction with fluid flow controloperations may be linked before, after, and/or during placement in theportion of the subterranean formation where fluid flow control isdesired. For example, some embodiments may involve a wellbore fluidcomprising the mineral particles described herein may be introduced intoa subterranean formation so as to penetrate a portion of thesubterranean formation; and contacting the wellbore fluid with a linkingagent so as to increase the viscosity of the wellbore fluid. In someembodiments, contacting the wellbore fluid with a linking agent mayyield a hardened mass as described further herein.

In some embodiments, the location providing fluid flow control (e.g.,where the first wellbore fluid was placed) may be treated so as toincrease fluid flow therethrough. For example, some embodiments mayinvolve treating an area of fluid flow control within a subterraneanformation with a wellbore fluid comprising a degradation agent so as todegrade and/or dissolve at least a portion of the mineral particlesdescribed herein in the area of fluid flow control.

One of ordinary skill in the art with the benefit of this disclosureshould understand the plurality of fluid flow control methods that mayutilize the mineral particles described herein. For example, someembodiments may involve introducing a first wellbore fluid comprisingthe mineral particles described herein capable of linking and linkingagents into a wellbore so as to incorporate the first wellbore fluidinto a gravel pack within the wellbore; introducing a second wellborefluid into the wellbore such that the first wellbore fluid at leastsubstantially blocks the second wellbore fluid from passing through thegravel pack; and contacting the first wellbore fluid with a thirdwellbore fluid comprising a degradation agent so as to at leastpartially degrade the mineral particles, thereby increasing thepermeability of the gravel pack.

In some embodiments, the fluid flow control operations described hereinmay involve the recovery and recycling the mineral particles describedherein. For example, after degradation of an area of fluid loss control,the resultant fluid may be recovered and recycled according to anysuitable recovery and recycling method described herein suitable for usein conjunction with the mineral particles utilized.

Base fluids suitable for use in conjunction with wellbore fluidssuitable for use in conjunction with fluid flow control operations may,in some embodiments, include any of the base fluids described herein inrelation to wellbore fluids in general. In some embodiments, wellborefluids suitable for use in conjunction with fluid flow controloperations may be foamed as described herein in relation to wellborefluids in general.

In some embodiments, the wellbore fluids and/or wellbore additivesdescribed herein suitable for use in conjunction with fluid flow controloperations may optionally further comprise additional componentsdescribed herein in relation to wellbore fluids in general. Examples ofpreferred additional components may, in some embodiments, include, butare not limited to, filler particles, salts, weighting agents, inertsolids, fluid loss control agents, emulsifiers, dispersion aids,corrosion inhibitors, emulsion thinners, emulsion thickeners,viscosifying agents, gelling agents, crosslinking agents, surfactants,cement particulates, proppants, gravel particulates, lost circulationmaterials, pH control additives, breakers, defoaming agents, biocides,stabilizers, scale inhibitors, gas hydrate inhibitors, oxidizers,reducers, friction reducers, clay stabilizing agents, set accelerators,set retarders, and combinations thereof.

III.d. Drilling

In some embodiments, the mineral particles described herein may beuseful in drilling operations. Some embodiments may involve drilling awellbore penetrating a subterranean formation with a wellbore fluid thatcomprises mineral particles described herein. In some embodiments, themineral particles described herein may be useful in at least one of:suspending wellbore cuttings (e.g., by contributing to the fluidviscosity and/or sag control), maintaining wellbore pressure (e.g., bycontributing to sag control), incorporating into filter cakes thatprovide fluid loss control, and the like. Further, mineral particlesdescribed herein may be chosen to mitigate abrasion of wellbore toolsutilized during drilling.

Some embodiments may involve forming a filter cake that comprisesmineral particles described herein (optionally linked) in a wellbore soas to provide fluid loss control. Some embodiments may involve cleaningup the filter cake by contacting the filter cake with a degradationagent so as to dissolve degradable mineral particles incorporatedtherein.

In some embodiments, the fluid flow control operations described hereinmay involve the recovery and recycling the mineral particles describedherein. For example, after degradation of an area of fluid loss control,the resultant fluid may be recovered and recycled according to anysuitable recovery and recycling method described herein suitable for usein conjunction with the mineral particles utilized.

Base fluids suitable for use in conjunction with wellbore fluidssuitable for use in conjunction with drilling operations may, in someembodiments, include any of the base fluids described herein in relationto wellbore fluids in general. In some embodiments, wellbore fluidssuitable for use in conjunction with drilling operations may be foamedas described herein in relation to wellbore fluids in general.

In some embodiments, the wellbore fluids and/or wellbore additivesdescribed herein suitable for use in conjunction with drillingoperations may optionally further comprise additional componentsdescribed herein in relation to wellbore fluids in general. Examples ofpreferred additional components may, in some embodiments, include, butare not limited to, filler particles, salts, weighting agents, inertsolids, fluid loss control agents, emulsifiers, dispersion aids,corrosion inhibitors, emulsion thinners, emulsion thickeners,viscosifying agents, gelling agents, crosslinking agents, surfactants,cement particulates, proppants, gravel particulates, lost circulationmaterials, pH control additives, breakers, defoaming agents, biocides,stabilizers, scale inhibitors, gas hydrate inhibitors, oxidizers,reducers, friction reducers, clay stabilizing agents, set accelerators,set retarders, and combinations thereof.

III.e. On-The-Fly

As described above, the mineral particles described herein may allow foron-the-fly modifications of wellbore fluid properties and capabilities.In some embodiments, the conditions encountered in the wellbore and/orsubterranean formation may necessitate changing the properties and/orcharacteristics of the wellbore fluid on-the-fly (e.g., density,viscosity, level of sag, and the like). On-the-fly modifications may, insome embodiments, include, but are not limited to, changing theconcentration of the mineral particles in the wellbore fluid, changingthe type of mineral particles in the wellbore fluid (e.g., size, coatingor not, type of coating, and the like), changing the relative ratio oftwo or more mineral particles in the wellbore fluid, changing theconcentration of linking agents, introducing a degradation agent todegrade a weighting agent, and the like, and any combination thereof.

By way of nonlimiting example, a wellbore fluid utilizing two mineralparticles with different specific gravities (e.g., rhodochrosite andawaruite) may increase the relative concentration of the higher specificgravity particle to achieve a higher density fluid. Adjusting thedensity of the wellbore fluid may, in some embodiments, be useful whendrilling a wellbore so as to maintain the bottom hole pressure at alevel that mitigates damage to the subterranean formation (e.g.,minimizes fracturing and leak-off) while maintaining a high enoughpressure to minimize subterranean fluids from entering the wellbore.

In another example, the density of the wellbore fluid can be reducedon-the-fly with the addition of a degradation agent to degrade a mineralparticle (e.g., tenorite, awaruite, rhodochrosite, or the like). Similarto above such a change may be used to mitigate wellbore damage whiledrilling.

By way of another nonlimiting example, the viscosity of a wellbore fluidutilizing a linkable mineral particle (e.g., rhodochrosite) may bechanged on-the-fly with the addition of linking agents for an increaseor the addition of a degradation agent for a decrease. In drillingoperations, the viscosity of the wellbore fluid may, at least in part,assist in suspending cuttings and bringing them to the surface. However,if too high a viscosity is reached, then pumping the fluid becomesexcessively energy intensive. The on-the-fly modification of theviscosity may assist in enhancing the efficacy while minimizing theenergy use and cost associated with drilling.

Embodiments disclosed herein include:

A. a method that comprises introducing a wellbore fluid into a wellborepenetrating a subterranean formation, the wellbore fluid comprising abase fluid and a plurality of mineral particles that comprise at leastone selected from the group consisting of manganese carbonate, NixFe(x=2-3), copper oxide, and any combination thereof, the mineralparticles having a median diameter between about 5 nm and about 5000microns;

B. a method that comprises drilling a wellbore penetrating asubterranean formation with a wellbore fluid that comprises a base fluidand a plurality of mineral particles, the plurality of mineral particlescomprising at least one selected from the group consisting of manganesecarbonate, NixFe (x=2-3), copper oxide, and any combination thereof, andthe mineral particles having a median diameter between about 5 nm andabout 100 microns; and

C. a wellbore fluid that comprises a base fluid and a plurality ofmineral particles that comprise at least one selected from the groupconsisting of manganese carbonate, NixFe (x=2-3), copper oxide, and anycombination thereof.

Each of embodiments A, B, and C may have one or more of the followingadditional elements in any combination, unless otherwise provided for:Element 1: wherein the mineral particles comprise manganese carbonateand/or copper oxide and are formed by precipitation; Element 2: whereinat least some of the mineral particles have a shape selected from thegroup consisting of spherical, substantially spherical, ovular,substantially ovular, discus, platelet, flake, toroidal, dendritic,acicular, spiked with a substantially spherical or ovular shape, spikedwith a discus or platelet shape, rod-like, fibrous, polygonal, faceted,star-shaped, and any hybrid thereof; Element 3: wherein the mineralparticles have a diameter distribution that has at least one mode with astandard deviation of about 2% or less of a peak diameter of the mode;Element 4: wherein the mineral particles have a multi-modal diameterdistribution; Element 5: wherein the mineral particles have a coating onat least a portion of a surface of the mineral particles; Element 6:wherein the wellbore fluid has a density between about 7 pounds pergallon and about 50 pounds per gallon; Element 7: wherein the mineralparticles comprise manganese carbonate and/or copper oxide and themethod further comprises linking the mineral particles with a linkingagent so as to increase a viscosity of the wellbore fluid; Element 8:wherein the mineral particles comprise manganese carbonate and/or copperoxide and the method further comprises linking the mineral particleswith a linking agent so as to yield a hardened mass; Element 9: whereinthe mineral particles comprise manganese carbonate and/or copper oxideand the method further comprises contacting the wellbore fluid with asecond wellbore fluid that comprises a degradation agent so as to atleast partially degrade the mineral particles; Element 10: the methodfurther comprising forming a proppant pack with the wellbore fluid, theproppant pack comprising the mineral particles; Element 11: the methodfurther comprising drilling the wellbore while circulating the wellborefluid in the wellbore; Element 12: the method further comprisingproducing hydrocarbons from the subterranean formation; Element 13: themethod further comprising recovering the mineral particles; and Element14: the method further comprising recycling the mineral particles.

By way of non-limiting example, exemplary combinations applicable to A,B, C include: Element 1 in combination with at least one of Elements3-5; Element 5 in combination with at least one of Elements 7-9; Element1 in combination with at least one of Elements 7-9; Element 3 incombination with at least one of Elements 7-9; Element 1 in combinationwith at least one of Elements 10-14; Element 3 in combination with atleast one of Elements 10-14; Element 5 in combination with at least oneof Elements 10-14; at least two of Elements 1-5 in combination with atleast one of Elements 10-14; Element 6 in combination with any of theforegoing; and so on.

The exemplary mineral particles and related fluids disclosed herein maydirectly or indirectly affect one or more components or pieces ofequipment associated with the preparation, delivery, recapture,recycling, reuse, and/or disposal of the disclosed mineral particles andrelated fluids. For example, and with reference to FIG. 3, the disclosedmineral particles and related fluids may directly or indirectly affectone or more components or pieces of equipment associated with anexemplary wellbore drilling assembly 300, according to one or moreembodiments. It should be noted that while FIG. 3 generally depicts aland-based drilling assembly, those skilled in the art will readilyrecognize that the principles described herein are equally applicable tosubsea drilling operations that employ floating or sea-based platformsand rigs, without departing from the scope of the disclosure.

As illustrated, the drilling assembly 300 may include a drillingplatform 302 that supports a derrick 304 having a traveling block 306for raising and lowering a drill string 308. The drill string 308 mayinclude, but is not limited to, drill pipe and coiled tubing, asgenerally known to those skilled in the art. A kelly 310 supports thedrill string 308 as it is lowered through a rotary table 312. A drillbit 314 is attached to the distal end of the drill string 308 and isdriven either by a downhole motor and/or via rotation of the drillstring 308 from the well surface. As the bit 314 rotates, it creates awellbore 316 that penetrates various subterranean formations 318.

A pump 320 (e.g., a mud pump) circulates drilling fluid 322 (e.g., adrilling fluid comprising the mineral particles described herein)through a feed pipe 324 and to the kelly 310, which conveys the drillingfluid 322 downhole through the interior of the drill string 308 andthrough one or more orifices in the drill bit 314. The drilling fluid322 is then circulated back to the surface via an annulus 326 definedbetween the drill string 308 and the walls of the wellbore 316. At thesurface, the recirculated or spent drilling fluid 322 exits the annulus326 and may be conveyed to one or more fluid processing unit(s) 328 viaan interconnecting flow line 330. After passing through the fluidprocessing unit(s) 328, a “cleaned” drilling fluid 322 is deposited intoa nearby retention pit 332 (i.e., a mud pit). While illustrated as beingarranged at the outlet of the wellbore 316 via the annulus 326, thoseskilled in the art will readily appreciate that the fluid processingunit(s) 328 may be arranged at any other location in the drillingassembly 300 to facilitate its proper function, without departing fromthe scope of the disclosure.

One or more of the disclosed mineral particles may be added to thedrilling fluid 322 via a mixing hopper 334 communicably coupled to orotherwise in fluid communication with the retention pit 332. The mixinghopper 334 may include, but is not limited to, mixers and related mixingequipment known to those skilled in the art. In other embodiments,however, the disclosed mineral particles may be added to the drillingfluid 322 at any other location in the drilling assembly 300. In atleast one embodiment, for example, there could be more than oneretention pit 332, such as multiple retention pits 332 in series.Moreover, the retention put 332 may be representative of one or morefluid storage facilities and/or units where the disclosed mineralparticles may be stored, reconditioned, and/or regulated until added tothe drilling fluid 322.

As mentioned above, the disclosed mineral particles and related fluidsmay directly or indirectly affect the components and equipment of thedrilling assembly 300. For example, the disclosed mineral particles andrelated fluids may directly or indirectly affect the fluid processingunit(s) 328 which may include, but is not limited to, one or more of ashaker (e.g., shale shaker), a centrifuge, a hydrocyclone, a separator(including magnetic and electrical separators), a desilter, a desander,a separator, a filter (e.g., diatomaceous earth filters), a heatexchanger, any fluid reclamation equipment. The fluid processing unit(s)328 may further include one or more sensors, gauges, pumps, compressors,and the like used to store, monitor, regulate, and/or recondition theexemplary mineral particles and related fluids.

The disclosed mineral particles and related fluids may directly orindirectly affect the pump 320, which representatively includes anyconduits, pipelines, trucks, tubulars, and/or pipes used to fluidicallyconvey the mineral particles and related fluids downhole, with pumps,compressors, or motors (e.g., topside or downhole) used to drive themineral particles and related fluids into motion, any valves or relatedjoints used to regulate the pressure or flow rate of the mineralparticles and related fluids, and any sensors (i.e., pressure,temperature, flow rate, etc.), gauges, and/or combinations thereof, andthe like. The disclosed mineral particles and related fluids may alsodirectly or indirectly affect the mixing hopper 334 and the retentionpit 332 and their assorted variations.

The disclosed mineral particles and related fluids may also directly orindirectly affect the various downhole equipment and tools that may comeinto contact with the mineral particles and related fluids such as, butnot limited to, the drill string 308, any floats, drill collars, mudmotors, downhole motors and/or pumps associated with the drill string308, and any MWD/LWD tools and related telemetry equipment, sensors ordistributed sensors associated with the drill string 308. The disclosedmineral particles and related fluids may also directly or indirectlyaffect any downhole heat exchangers, valves and corresponding actuationdevices, tool seals, packers and other wellbore isolation devices orcomponents, and the like associated with the wellbore 316. The disclosedmineral particles and related fluids may also directly or indirectlyaffect the drill bit 314, which may include, but is not limited to,roller cone bits, polycrystalline diamond cutter (PDC) bits, naturaldiamond bits, any hole openers, reamers, coring bits, etc.

While not specifically illustrated herein, the disclosed mineralparticles and related fluids may also directly or indirectly affect anytransport or delivery equipment used to convey the mineral particles andrelated fluids to the drilling assembly 300 such as, for example, anytransport vessels, conduits, pipelines, trucks, tubulars, and/or pipesused to fluidically move the mineral particles and related fluids fromone location to another, any pumps, compressors, or motors used to drivethe mineral particles and related fluids into motion, any valves orrelated joints used to regulate the pressure or flow rate of the mineralparticles and related fluids, and any sensors (i.e., pressure andtemperature), gauges, and/or combinations thereof, and the like.

While not specifically illustrated herein, one of ordinary skill in theart should recognize the modifications to drilling assembly 300 to allowfor performing other operations described herein including, but notlimited to, cementing operations, fracturing operations, and fluid flowcontrol operations.

In some embodiments, a wellbore drilling assembly may comprise a pump influid communication with a wellbore via a feed pipe; and a wellborefluid described herein disposed in at least one selected from the groupconsisting of the pump, the feed pipe, the wellbore, and any combinationthereof.

In some embodiments, a wellbore drilling assembly may comprise a pump influid communication with a wellbore via a feed pipe; a drill string withdrill bit attached to the distal end of the drill string; and a wellborefluid described herein in contact with the drill bit.

In some embodiments, a wellbore drilling assembly may comprise a pumpcapable of introducing a fluid into a wellbore via a feed pipe; a fluidprocessing unit capable of receiving the fluid from a wellbore via aninterconnecting flow line; and a wellbore fluid described hereindisposed in at least one selected from the group consisting of the pump,the feed pipe, the wellbore, the interconnecting flow line, the fluidprocessing unit, and any combination thereof.

In some embodiments, a wellbore drilling assembly may comprise a pumpcapable of introducing a fluid into a wellbore via a feed pipe; a mixinghopper upstream of the pump; and a wellbore fluid described hereindisposed in at least one selected from the group consisting of the pump,the feed pipe, the wellbore, and any combination thereof. The mixinghopper may be useful, in some embodiments, for implementing on-the-flychanges to the wellbore fluids described herein.

In the foregoing wellbore drilling assembly embodiments suitablewellbore fluids described herein may include, but are not limited to,

(a) a wellbore fluid that comprises a base fluid and a plurality ofmineral particles that comprise at least one selected from the groupconsisting of manganese carbonate, Ni_(x)Fe (x=2-3), copper oxide, andany combination thereof, the mineral particles having a median diameterbetween about 5 nm and about 5000 microns;

(b) a wellbore fluid comprising a base fluid, a plurality of firstmineral particles, and a plurality of second mineral particles such thatthe first mineral particles and the second mineral particles have amultiparticle specific gravity of about 3 to about 20;

(c) a wellbore fluid with a density of about 7 ppg to about 50 ppg andcomprising a base fluid and a plurality of linkable mineral particles;

(d) a wellbore fluid with a density of about 7 ppg to about 50 ppg andcomprising a base fluid and a plurality of degradable mineral particles;

(e) a wellbore fluid with a density of about 7 ppg to about 50 ppg andcomprising a base fluid, a plurality of first mineral particles having aspecific gravity of about 2.6 to about 20, a plurality of second mineralparticles having a specific gravity of about 5.5 to about 20; and aplurality of lubricating particulates having a specific gravity of about2.6 to about 20, wherein the first mineral particles, the second mineralparticles, and the lubricant particles are different, and wherein thefirst mineral particles, the second mineral particles, and the lubricantparticles have a multiparticle specific gravity of about 3 to about 20;and

(f) any of the wellbore fluids described in Embodiments A-C optionallyincluding at least one of Elements 1-14 relating to the wellbore fluid.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered,combined, or modified and all such variations are considered within thescope and spirit of the present invention. The invention illustrativelydisclosed herein suitably may be practiced in the absence of any elementthat is not specifically disclosed herein and/or any optional elementdisclosed herein. While compositions and methods are described in termsof “comprising,” “containing,” or “including” various components orsteps, the compositions and methods can also “consist essentially of” or“consist of” the various components and steps. All numbers and rangesdisclosed above may vary by some amount. Whenever a numerical range witha lower limit to an upper limit is disclosed, any number and anyincluded range falling within the range is specifically disclosed. Inparticular, every range of values (of the form, “from about a to aboutb,” or, equivalently, “from approximately a to b,” or, equivalently,“from approximately a-b”) disclosed herein is to be understood to setforth every number and range encompassed within the broader range ofvalues. Also, the terms in the claims have their plain, ordinary meaningunless otherwise explicitly and clearly defined by the patentee.Moreover, the indefinite articles “a” or “an,” as used in the claims,are defined herein to mean one or more than one of the element that itintroduces. If there is any conflict in the usages of a word or term inthis specification and one or more patent or other documents that may beincorporated herein by reference, the definitions that are consistentwith this specification should be adopted.

The invention claimed is:
 1. A wellbore drilling assembly comprising: apump in fluid communication with a wellbore via a feed pipe; and awellbore fluid disposed in at least one selected from the groupconsisting of the pump, the feed pipe, the wellbore, and any combinationthereof, wherein the wellbore fluid comprises a base fluid and aplurality of mineral particles that comprise Ni_(x)Fe, wherein 2≦x≦3,and have a median diameter between about 5 nm and about 5000 microns. 2.The wellbore drilling assembly of claim 1, wherein the mineral particlesfurther comprise copper oxide and are formed by precipitation.
 3. Thewellbore drilling assembly of claim 1, wherein at least some of themineral particles have a shape selected from the group consisting ofspherical, substantially spherical, ovular, substantially ovular,discus, platelet, flake, toroidal, dendritic, acicular, spiked with asubstantially spherical or ovular shape, spiked with a discus orplatelet shape, rod, fibrous, polygonal, faceted, and star-shaped. 4.The wellbore drilling assembly of claim 1, wherein the mineral particleshave a diameter distribution that has at least one mode with a standarddeviation of about 2% or less of a peak diameter of the at least onemode.
 5. The wellbore drilling assembly of claim 1, wherein the mineralparticles have a multi-modal diameter distribution.
 6. The wellboredrilling assembly of claim 1, wherein the mineral particles have acoating on at least a portion of a surface of the mineral particles. 7.The wellbore drilling assembly of claim 1, wherein the wellbore fluidhas a density between about 7 pounds per gallon and about 50 pounds pergallon.
 8. A wellbore drilling assembly comprising: a pump in fluidcommunication with a wellbore via a feed pipe; a drill string with drillbit attached to a distal end of the drill string; and a wellbore fluidin contact with the drill bit, wherein the wellbore fluid comprises abase fluid and a plurality of mineral particles, and wherein theplurality of mineral particles comprise Ni_(x)Fe, wherein 2≦x≦3, andhave median diameter between about 5 nm and about 100 microns.
 9. Thewellbore drilling assembly of claim 8, wherein the mineral particlesfurther comprise copper oxide and are formed by precipitation.
 10. Thewellbore drilling assembly of claim 8, wherein at least some of themineral particles have a shape selected from the group consisting ofspherical, substantially spherical, ovular, substantially ovular,discus, platelet, flake, toroidal, dendritic, acicular, spiked with asubstantially spherical or ovular shape, spiked with a discus orplatelet shape, rod, fibrous, polygonal, faceted, and star-shaped. 11.The wellbore drilling assembly of claim 8, wherein the mineral particleshave a diameter distribution that has at least one mode with a standarddeviation of about 2% or less of a peak diameter of the at least onemode.
 12. The wellbore drilling assembly of claim 8, wherein the mineralparticles have a multi-modal diameter distribution.
 13. The wellboredrilling assembly of claim 8, wherein the mineral particles have acoating on at least a portion of a surface of the mineral particles. 14.The wellbore drilling assembly of claim 8, wherein the wellbore fluidhas a density between about 7 pounds per gallon and about 50 pounds pergallon.
 15. A wellbore drilling assembly comprising: a pump capable ofintroducing a fluid into a wellbore via a feed pipe; a fluid processingunit capable of receiving the fluid from a wellbore via aninterconnecting flow line; and a wellbore fluid disposed in at least oneselected from the group consisting of the pump, the feed pipe, thewellbore, the interconnecting flow line, the fluid processing unit, andany combination thereof, wherein the wellbore fluid comprises a basefluid and a plurality of mineral particles that comprise Ni_(x)Fe,wherein 2≦x≦3, and have a median diameter between about 5 nm and about5000 microns.
 16. The wellbore drilling assembly of claim 15, whereinthe mineral particles further comprise copper oxide and are formed byprecipitation.
 17. The wellbore drilling assembly of claim 15, whereinat least some of the mineral particles have a shape selected from thegroup consisting of spherical, substantially spherical, ovular,substantially ovular, discus, platelet, flake, toroidal, dendritic,acicular, spiked with a substantially spherical or ovular shape, spikedwith a discus or platelet shape, rod, fibrous, polygonal, faceted, andstar-shaped.
 18. The wellbore drilling assembly of claim 15, wherein themineral particles have a diameter distribution that has at least onemode with a standard deviation of about 2% or less of a peak diameter ofthe at least one mode.
 19. The wellbore drilling assembly of claim 15,wherein the mineral particles have a multi-modal diameter distribution.20. The wellbore drilling assembly of claim 15, wherein the mineralparticles have a coating on at least a portion of a surface of themineral particles.